Indo-Pacific Power Sector Shows Resilience Amid Energy Crunch
BGA’s Energy Crisis series tracks the Indo-Pacific fallout from the Iran conflict, with a focus on how shocks to oil, liquefied natural gas (LNG) and shipping are reshaping energy security across key markets. Building on prior editions, this update takes a more focused look at power and electricity market demand and shifting trends across Asia.
The Indo-Pacific’s power sector remains largely resilient, with modest impact from the conflict-induced energy crunch. However, some countries are more exposed and affected than others.
The energy supply bottleneck is impacting the power sector through higher LNG and coal import prices and shipping cost inflation rather than physical supply shortfalls. Countries heavily dependent on imported LNG, including Singapore (93 percent gas-fired), Japan (32 percent), Korea (28 percent), Taiwan (48 percent) and Thailand (60 percent), bear the greatest cost pressure. Indonesia and Vietnam remain the most insulated, anchored by domestic coal and hydropower. India faces a split picture: retail tariffs are shielded, but industrial gas users are absorbing 40 percent supply cuts and sharp evening spot-price spikes.
From a power price perspective, Indonesia and Vietnam have seen no changes in tariffs following the Iran conflict, both supported by domestic coal and hydropower production. At the other extreme, Singapore and Malaysia are the most affected. Singapore’s commercial electricity rates surged 25 percent — from US$0.19 to $0.25 per kilowatt-hour (kWh) — between February and May. Malaysia’s household tariffs rose approximately 17 percent (from US$0.06 to US$0.07 per kWh), with data-center rates climbing further. The Philippines recorded an 8.8 percent residential rate increase driven by a rising generation costs, while India’s open-access industrial consumers face evening spot prices of US$0.11 to 0.13 per kWh, nearly double regulated tariffs.
Regarding the energy transition, the crisis is producing a dual-track response: accelerating long-term renewable investment while justifying short-term recourse to fossil fuels. No country has reversed its clean energy trajectory, but several have unlocked or extended fossil fuel capacity as an interim buffer. Japan temporarily eased restrictions on inefficient coal plants and restarted a major nuclear unit, reducing annual LNG needs by approximately 1.1 million tons. The Philippines is expediting pre-approved coal permits under its existing moratorium. On balance, the crisis is leaning toward coal and nuclear in the short term while reinforcing renewable investment in the medium term, delaying the transition at the margin but not reversing it.
BGA also foresees potential complexities related to the Association of Southeast Asian Nations (ASEAN) Power Grid project despite Southeast Asia’s resiliency. Malaysia has explicitly noted that worsening domestic supply conditions could lead policymakers to prioritize the national grid over regional export commitments, posing a direct risk to power grid cohesion.
Conversely, Singapore is actively advancing the framework; it signed the world’s first legally binding bilateral essential-supply agreement with New Zealand in May and is pursuing similar arrangements with Australia and within ASEAN. Small-scale cross-border trade between Vietnam, Laos and Thailand continues to function under stress, demonstrating that sub-regional links remain operative.
The overarching risk is that national energy security instincts fragment rather than deepen regional grid integration, making Singapore’s push for binding supply-sharing frameworks the most consequential ASEAN Power Grid development to emerge from the crisis.
Looking ahead, Asia’s power markets are expected to remain broadly resilient but increasingly shaped by fuel cost volatility, energy security policies and accelerating industrial electricity demand. Governments across the region are likely to maintain politically sensitive tariff interventions and subsidies through at least the northern hemisphere summer peak-demand season, though fiscal pressure may gradually force more selective pass through of costs to commercial and industrial users.
At the same time, several structural milestones are expected to accelerate, including additional nuclear restarts in Japan, expanded battery storage and grid flexibility measures in India and Korea, further solar and transmission investments in ASEAN and deeper regional discussions around energy security. For corporates, the key strategic risks to watch are rising electricity price volatility for large industrial users, tightening competition for long term renewable power-purchase agreements, grid reliability constraints linked to artificial intelligence (AI) and data-center growth. Companies should also note the potential for governments to prioritize domestic energy security over regional export commitments if geopolitical tensions persist.
Future Iterations: Opportunity for Inputs
BGA will structure the next phase of this update series around targeted deep-dives on how a prolonged crisis is reshaping markets beyond near-term effects. Upcoming editions will focus on the following:
- Industrial impacts across petrochemicals and manufacturing supply chains.
- Agriculture, food and fertilizer systems, particularly in energy-import dependent markets.
As we refine these analyses, we want to ensure they align with your most pressing priorities. Please share specific questions, sectors or geographies where deeper insight would be most valuable — whether on exposure to risks, policy outlooks or market-entry considerations. We will tailor forthcoming updates to support your decision-making.
Please contact BGA Director of Energy, Climate and Resources (ECR) Chayamon Srisongkram, BGA Director of ECR Mardika Parama or BGA Head of Research Murray Hiebert with questions or comments.
Australia
| Australia Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 17% | – |
| Diesel/Oil | 2% | 90% |
| Coal | 45% | – |
| Nuclear | – | – |
| Hydro | 5% | – |
| Solar | 18% | – |
| Wind | 12% | – |
| Geothermal | – | – |
| Others | 1% | – |
| Australia Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy |
| Household | Average household electricity rates were AUD 0.35-AUD 0.40 (US$0.25-US$0.29)/kWh, with typical annual bills of AUD 1,650-AUD 2,350 (US$1,183-US$1,685); about AUD 400-AUD 580 (US$287-US$416) per quarter. | After the Iran conflict began, Australian 2027 wholesale electricity futures rose 11%-16% across the National Electricity Market. Household retail bills remain largely insulated in the near term due to retailers’ multi-year hedging and upcoming default retail tariffs. | The federal Energy Bill Relief Fund ended on December 31, 2025. Governments continue to offer household solar and battery rebates. Under the federal government’s Solar Sharer Offer, starting July 1, retailers will provide households with smart meters at least three hours of free electricity during midday peak solar generation. |
| Low/Medium Intensity Commercial | In February, typical retail electricity rates for Australian small and medium enterprises ranged from AUD 0.28-AUD 0.45 (US$0.20-US$0.32)/kWh, with average annual bills of AUD 5,000-AUD 20,000 (US$3,585-US$14,340). | No material changes since the Iran conflict began. | N/A |
| High Intensity Commercial/Industry | Heavy industrial users and large emitters typically pay AUD 0.08-AUD 0.14 (US$0.06-US$0.10)/kWh. Rates are usually customized and negotiated directly with retailers or generators through power-purchase agreements, rather than set by standard retail tariffs. | No material changes since the Iran conflict began. | The federal government supports large-scale renewable projects mainly through the Capacity Investment Scheme, the Australian Renewable Energy Agency, the Clean Energy Finance Corporation and the Large-scale Renewable Energy Target. |
Market Situation
Australia’s power sector remains relatively insulated from the Iran conflict because it relies mainly on domestic coal, gas and renewable generation rather than imported fuel. The main near-term risk is higher wholesale power and liquid-fuel costs, not a physical supply shortfall. Wholesale electricity prices were lower in the first quarter of 2026 than a year earlier, supported by stronger battery and solar output. On May 26, the Australian Energy Regulator released its Default Market Offer (DMO) for 2026-2027. From July 1, electricity prices will fall for most households and small businesses in the three regions where the DMO applies (New South Wales, Southeast Queensland and South Australia).
Power Procurement Risk
Procurement risk is more acute in project delivery and price formation than in immediate fuel availability. Shipping disruptions, higher insurance costs and supply-chain delays could further slow renewable deployment, which is already constrained by grid bottlenecks, slow permitting, rising construction costs and local opposition in some areas. Gas-fired peaking plants still help set marginal power prices, so higher international gas prices can lift electricity futures even when domestic supply remains adequate. The government’s March 23 expectations for data centers reinforce this direction by calling on operators to underwrite new renewable supply, fund their own grid connections and support demand flexibility rather than add pressure to the wider system.
Policy Response
The government is increasingly focused on shielding domestic users from global gas volatility while keeping the energy transition on track. In May, it announced a domestic gas reservation scheme that will require east coast LNG exporters to supply a portion of production to the local market from July 1, 2027, equivalent to 20 percent of LNG exports. Contracts entered before December 22, 2025, will be respected. Canberra argues the measure will help avoid forecast shortfalls and put downward pressure on domestic gas prices, though industry groups warn it could weaken investment incentives.
Looking Ahead
The crisis is reinforcing Australia’s push toward renewables, storage and grid flexibility rather than changing its broader transition path. Gas remains an important transition fuel, especially for balancing and reliability, but policy still favors cleaner domestic generation as a hedge against imported-fuel shocks. The debate is sharpening around how to balance affordability, reliability and transition speed, particularly as some political voices continue to support extending the life of coal-fired generation to cover delays in renewable build-out.
Cambodia
| Cambodia Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | – | – |
| Diesel/Oil | 38% | 100% |
| Coal | 10%-15% | 99% |
| Nuclear | – | – |
| Hydro | 25% | Domestic generation |
| Solar | 5% | Domestic generation |
| Wind | – | – |
| Geothermal | – | – |
| Others | 1% | Biomass/waste sourced domestically |
| Cambodia Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | The power tariff for households in Cambodia differs based on low-medium intensity. The current tariff ranges between $0.15-$0.18/kWh. | No Change | The tariff is based on higher consumption to higher unit prices. The government subsidized tiers that exist for low-income users are $0.10/kWh for basic usage, but with limited volume. |
| Low/Medium Intensity Commercial | For commercial users with medium intensity, the power tariff ranges from $0.16-$0.20/kWh. Mid-size office buildings typically cluster around $0.17-0.19/kWh (derived from tariff structure) | No Change | The commercial tariffs are like or slightly above the residential high-tier rates based on the location of cities and provinces, voltage connection and contracted load. |
| High Intensity Commercial/Industry | For commercials with high intensity, the power tariff ranges from $0.12-$0.18/kWh (wide range depending on contract). For large factories, the tariff ranges between $0.12-$0.15/kWh. For high-reliability load (e.g., data centers) can be higher due to backup plus reliability costs. | No Change | For the low unit cost at high consumption/high voltage, the government has periodically reduced tariffs for industrial users to support competitiveness. |
Market Situation
Cambodia’s power sector remains highly vulnerable to external fuel shocks because the country depends entirely on imported petroleum products and lacks domestic refining capacity. Energy Minister Keo Rottanak has said normal fuel stocks cover less than one month of supply. That leaves electricity costs and broader energy prices exposed to global volatility. The main near-term risk is higher fuel and transport costs rather than an immediate grid-wide power shortage. Inflation rose to 5.8 percent year over year in April, driven largely by transport, food and utility costs. The most exposed sectors are manufacturing, logistics, industrial users and households, especially where operating costs are sensitive to diesel and imported fuel prices.
Power Procurement Risk
Cambodia is not a power exporter, meaning the issue is not export curbs but rising import costs and tighter fuel availability. Procurement risk is concentrated in imported oil products, while broader power-sector risk stems from the cost of securing fuel and passing those costs through the economy. Recent sourcing shifts toward Singapore and Malaysia have helped offset supply disruptions from some neighboring markets, but they do not change Cambodia’s underlying dependence on imported fuel. Over time, this strengthens the case for greater diversification, more renewable capacity and stronger energy-security buffers.
Policy Response
The government has responded with tax and pricing measures to limit the pass-through of higher global fuel costs. Since March, Cambodia has reduced import duties and value-added tax on fuel and cut or removed selected fuel taxes, especially on diesel, to stabilize retail prices. Officials have also emphasized efforts to diversify fuel sourcing, including increased imports from Singapore and Malaysia, while exploring additional options such as India. More broadly, the policy direction favors short-term price relief alongside longer-term efforts to strengthen energy resilience and reduce import dependence.
Looking Ahead
The crisis is likely to reinforce Cambodia’s push toward renewables, storage and stronger fuel-security planning, even if imported fuel remains part of the mix in the near term. Policymakers appear focused on diversifying supply, improving reserves and advancing projects that can reduce long-term exposure to imported oil products. Some proposed LNG and hydropower projects could support that shift over time, but near-term resilience will still depend mainly on import management, fiscal support and gradual expansion of domestic clean-energy capacity.
China
| China Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 5%, with LNG around 3-5% | 40% |
| Diesel/Oil | – | 70% |
| Coal | 55% | 5% |
| Nuclear | 40% | 100% |
| Hydro | – | |
| Solar | – | |
| Wind | – | |
| Geothermal | – | |
| Others | – | – |
Market Situation
China’s predominantly coal and renewables generation mix (around 95 percent of output) provides structural insulation from the Strait of Hormuz disruption. The primary risk sits in coastal provinces with gas-fired plant clusters dependent on Qatari LNG, offline since early March. Spot market access is more constrained than by Japan or Korea, creating a localized procurement squeeze heading into summer peak demand. Exposure is geographically concentrated and sharper than national averages suggest.
Power Procurement Risk
Gas-fired power in coastal provinces faces the clearest near-term pressure. The Oxford Institute of Energy Studies noted in April that Chinese LNG cargoes are being remarketed, reducing supply for domestic gas plants, and a Sinopec LNG terminal in Tianjin has been canceled. Small, privately-owned “teapot refineries’ in Shandong, processing roughly 25 percent of Chinese refinery capacity on discounted Iranian crude, face compounding pressure from both the Hormuz blockade and U.S. sanctions.
The U.S. Office of Foreign Assets Control designated five Chinese teapot refiners between March 2025 and April 2026 to the specially designated nationals list which means they are cut off from the global financial and punished for violating U.S. sanctions. Hengli Petrochemical (Dalian) added to this list April 24, and other sanctions were imposed on approximately 40 shadow fleet vessels.
The U.S. Treasury warned global financial institutions of secondary sanctions risk for dealings with the designated refineries April 28. These refiners have narrow margins and limited alternative crude options, creating risk of output cuts that could tighten domestic refined product supply. Russia’s confirmed compensatory energy cooperation offers the most Hormuz-insulated alternative but cannot fully replace the Persian Gulf volumes. Coastal industrial and manufacturing users face the sharpest near-term cost and availability pressure, compounded by sanctions-driven uncertainty over teapot refinery output.
Policy Response
The National Development and Reform Commission has deployed three rounds of retail fuel price intervention. The March 23 controls were the first since China’s current pricing mechanism was introduced in 2013, capping the gasoline increase at 1,160 yuan per ton against a market implied CNY 2,205 ($325). A second round on April 7-8 again capped increases below market levels; prices were cut April 21 as the average across the preceding 10 working days fell below the previous cycle. No electricity price adjustments have been confirmed. The Ministry of Commerce issued a prohibition order under China’s 2021 Blocking Rules May 2, barring compliance inside China with U.S. sanctions on all five designated refineries — the first practical deployment of the rules since they were enacted. China is holding domestic prices stable while legally shielding sanctioned refiners, but the order puts any institution with exposure to both jurisdictions in direct legal conflict.
Looking Ahead
The crisis is reinforcing both transition tracks. Gas loses near-term favor as one terminal is cancelled and teapot feedstock faces sanctions pressure alongside supply disruption. The 15th Five-Year Plan’s energy security framing, the National Development and Reform Commission, the National Energy Administration renewable pricing reform and China’s formal accession to the Declaration to Triple Nuclear Energy all point toward accelerated electrification. The 3.6 terawatt wind and solar target for 2035 is likely to be brought forward. The outlook is structurally bearish for gas and bullish for renewables and nuclear, with long-term implications for regional LNG demand projections.
India
| India Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas* | 1.4% | 45-50% |
| Diesel/Oil | 85% | |
| Coal | 69.7% | 22% |
| Nuclear | 3% | 30-40% |
| Hydro | 9.7% | – |
| Solar | 9.5% | – |
| Wind | 5.8% | – |
| Geothermal | – | – |
| Others | 0.9% | – |
*Gas is a larger component, ~20 gigawatts (GW) installed capacity of gas, and ~500 megawatts (MW) is diesel.
| India Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | Regulated slab tariff at $0.04-$0.08/kWh National average $0.06/kWh | Regulated tariff unchanged. High-consumption urban households reached upper slabs of $0.11-$0.13/kWh No emergency tariff revision triggered | Yes — state electricity subsidies totaling $25.9 billion in fiscal year 2025 Tariff not passed through to consumers despite rising procurement costs. |
| Low/Medium Intensity Commercial | Low tension/high tension commercial tariffs at $0.07-$0.10/kWh Commercial users paid 30-60% premium over domestic consumers due to cross-subsidy structure | $0.07–$0.10/kWh. Regulated tariffs unchanged However, Fuel and Power Purchase Cost Adjustment surcharges of $0.002-$0.01/unit added in some states amid rising procurement costs. | Partial — no direct subsidy; benefits indirectly from regulated caps Cross-subsidizes domestic/agricultural consumers, meaning these users pay above cost-of-supply. |
| High Intensity Commercial/Industry | $0.07-$0.11/kWh on regulated high tension industrial tariff Open-access users on Indian Energy Exchange at $0.04/unit average (February was a low-price month with strong supply liquidity). Green day-ahead market at $0.04/unit. | $0.08-$0.13/kWh. Indian Energy Exchange day-ahead market average clearing price rose to $0.0566/unit in April 2026 (+1% year on year, but with severe intraday spikes to $0.11-$0.13/kWh during evening peak hours) May expected to remain elevated with heatwaves. | No — no subsidy. High tension/open-access industrial users bear full market price exposure Data centers procuring via open access or short-term power-purchase agreements face maximum cost pressure during evening peak. |
Market Situation
India’s peak power demand hit 265.4 gigawatts (GW) in May and is projected to approach 271 GW this summer. Domestic coal production rose 5 percent year over year to 1 billion metric tons in fiscal year 2025, while coal imports fell 8.1 percent. Remaining imports are concentrated more in coking coal for steel than in power generation. Gas-based capacity of about 20 GW, or less than 4 percent of installed capacity, is typically supported by central directives during peak demand, but no such order was issued in 2026. Gas supplies remain prioritized for city gas distribution and fertilizer, while coal remains the main baseload fuel. The sharpest stress is therefore concentrated in industrial gas users facing supply cuts of up to 40 percent and in commercial consumers on short-term contracts exposed to evening peak prices.
Power Procurement Risk
The key risk has shifted from capacity shortages to cost and flexibility constraints. Coal availability remains sufficient, and peak demand continues to be met, but higher import prices still create pass-through risk for plants reliant on imported coal. The structural gap is limited gas-fired peak capacity to manage the sharp evening ramp after solar output falls. Consumers in day-ahead and real-time markets face high volatility, while long-term power purchase agreements provide only partial insulation from scarcity premiums during tight conditions. India continues electricity trade with Bangladesh, Bhutan and Nepal, with cross-border trade in the Bangladesh, Bhutan, India, Nepal subregion totaling about 21 terawatts in 2024.
Policy Response
Households remain partly shielded from electricity-price shocks but are seeing broader fuel inflation. State electricity subsidies remain substantial, with no direct tariff pass-through for most retail power users. On the supply side, the government deferred thermal plant maintenance to add about 10,000 MW of temporary capacity for the summer peak. Gas policy continues to prioritize fertilizer and city gas distribution over the power sector. India is also considering support for long-duration energy storage under Battery Storage Vision 2047, including possible viability-gap funding and interest subvention.
Looking Ahead
India aims to raise natural gas’s share in the energy mix from 6 percent to 15 percent, but growth is likely to come mainly from city gas distribution rather than power generation. In electricity, the focus is shifting toward solar paired with storage. Battery Storage Vision 2047 is expected to support long-duration storage, as India has installed only about 795 megawatt-hours (MWh) of battery storage against a projected need of about 47 gigawatt-hours (GWh) by fiscal 2027. Despite diversification efforts, coal is expected to remain the backbone of India’s power system in the near term.
The system is increasingly constrained by fuel-cost inflation and a structural lack of gas-fired evening flexibility, not by a lack of generation capacity.
Indonesia
| Indonesia Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 26% | – |
| Diesel/Oil | 5.8% | 11% |
| Coal | 54% | – |
| Nuclear | – | – |
| Hydro | 7% | – |
| Solar | 0.9% | – |
| Wind | 0.15% | – |
| Geothermal | 2.6% | – |
| Others | 3.6% | – |
| Indonesia Energy Price* | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | $0.09/kWh on average | $0.09/kWh on average | Yes. Some low-income households received government subsidies. Most electricity consumers continued to benefit from stable tariffs, as PLN has made little to no price adjustments since 2018 and the government absorbed most of the price gap. |
| Low/Medium Intensity Commercial | $0.10/kWh on average | $0.10/kWh on average | Partial. This group enjoyed relatively stable tariffs with Perusahaan Listrik Negara (PLN) only making limited adjustments over the past years, and the government absorbed most of the price gap. |
| High Intensity Commercial/Industry | $0.07/kWh on average | $0.07/kWh on average | Partial. This group enjoyed relatively stable tariffs with PLN only made limited adjustments over the past years and the government absorbed most of the price gap. |
*Price listed from state-owned power company PLN in Java region. Price set by Independent Power Producers and in Batam Island might differ.
Market Situation
Indonesia’s power sector remains relatively insulated from the direct impacts of the Iran conflict and broader Gulf-related energy supply disruptions. Unlike many countries that rely heavily on imported gas or oil for electricity generation, Indonesia’s power mix is still dominated by domestically supplied coal, which accounts for more than 44 percent of total generation. Diesel-fired power plants contribute only around 4.1 percent of electricity generation, limiting direct exposure to imported fuel price volatility. Since the conflict escalated in February, domestic electricity prices have remained stable, with the government indicating that existing tariff conditions will be maintained at least until early July. Existing domestic market obligation policies and coal price caps continue to provide additional buffers against external energy shocks.
Power Procurement Risk
A potentially more material concern for Indonesia’s coal sector is emerging not from the Iran conflict, but from recent domestic policy announced by the administration of President Prabowo Subianto. The president said the government plans to establish a new state agency to oversee exports of strategic commodities, with coal and crude palm oil identified as the initial focus sectors. The stated rationale is to reduce economic leakage and under-invoicing practices in commodity exports. Under the proposed mechanism, exporters may be required to sell commodities first to the agency, which would then conduct exports to international buyers.
While operational details remain unclear, industry players are increasingly concerned that the policy could fundamentally reshape contracting structures, pricing mechanisms and export negotiations. Several coal companies have indicated that uncertainty around implementation could affect production planning and future investment decisions, particularly if pricing flexibility and commercial margins become more constrained under a centralized export system.
If local producers scale back output due to the new state agency, neighboring countries relying on Indonesian coal exports may face supply disruptions for their power generation.
Policy Response and Looking Ahead
The government appears to be using the current crisis to reinforce its long-term energy transition and energy security narrative. The policy direction is to transition away from imported fuel dependence toward electrification of end-use demand, particularly in transportation. The government is preparing to reintroduce a value-added tax borne by government incentives for electric vehicles to accelerate adoption of electric cars. In parallel, Prabowo has introduced a 100 GW national solar program, signaling a longer-term ambition to increase renewable energy deployment while still maintaining coal as the primary baseload source in the near term, but it remains to be seen whether the government would introduce long-delayed reforms needed to improve the economics of renewables.
Japan
| Japan Energy Mix | ||
| Energy Source | Energy Mix (% of total generation, 2024) | Energy Source Import Share (% of total supply, 2024) |
| Natural Gas | 32.2% | 98% |
| Diesel/Oil | 7.2% | 99.7% |
| Coal | 28.1% | 99.7% |
| Nuclear | 9.4% | – |
| Hydro | 7.4% | – |
| Solar | 9.9% | – |
| Wind | 1.2% | – |
| Geothermal | 0.4% | – |
| Others | 4.2% | – |
| Japan Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | Standard S Plan (10A-60A): JPY 29.80/kWh ($0.19/kWh) (-120 kWh); JPY 36.40/kWh ($0.23/kWh) (121-300 kWh); JPY 40.49/kWh ($0.26/kWh) (301 kWh-) | Standard S Plan (10A-60A): JPY 29.80/kWh ($0.19/kWh) (-120 kWh); JPY 36.40/kWh ($0.23/kWh) (121-300 kWh); JPY 40.49 /kWh ($0.26/kWh) (301 kWh-) | Government subsidies have been provided during peak demand periods since January 2023. Previous subsidy round was from January to March 2026. The next subsidy round is expected to commence in July to September, with per‑kWh rates set at JPY 3.5 in July, JPY 4.5 in August and JPY 3.5 in September. |
| Low/Medium Intensity Commercial | JPY 25.57/kWh ($0.16/kWh) | JPY 25.57/kWh ($0.16/kWh) | Government subsidies have been provided during peak demand periods since January 2023. The previous subsidy round ran from January to March 2026, with per‑kWh rates set at JPY 4.5 in January and February and JPY 1.5 in March. |
| High Intensity Commercial/Industry | High Intensity Basic Plan: JPY 16.56/kWh ($0.10/kWh) | High Intensity Basic Plan: JPY 17.43/kWh ($0.11/kWh) | Government subsidies have been provided during peak demand periods since January 2023. The previous subsidy round ran from January to March 2026, with per‑kWh rates set at JPY 2.3 in January and February and JPY 0.8 in March. |
Market Situation
Japan remains heavily dependent on imported fossil fuels, particularly crude oil. Before the Iran crisis, approximately 94 percent of Japan’s crude oil imports originated from the Middle East, with nearly all shipments transiting the Strait of Hormuz. By contrast, dependence on Middle Eastern LNG was significantly lower, accounting for roughly 11 percent of total LNG imports, while only around 6 percent of LNG imports passed through the strait.
As a result, disruption of the Strait of Hormuz poses a more immediate risk to oil procurement than to electricity supply itself. This is because oil-fired power generation, which relies heavily on crude oil transported through the strait, accounted for only around 7 percent of Japan’s power generation mix before the crisis. In contrast, LNG-fired power generation, which has relatively limited dependence on the strait, accounted for more than 30 percent of the power mix, while coal-fired power, nuclear power, and renewable energy sources, all largely unaffected by a strait closure, together accounted for more than 60 percent.
Nevertheless, the government has taken precautionary measures in anticipation of higher LNG prices and tighter global supply conditions. Since April, operations of certain coal-fired power plants have resumed to reduce LNG consumption. In addition, commercial operation of Unit 6 at the Kashiwazaki-Kariwa Nuclear Power Station resumed in April. The restart is expected to reduce Japan’s annual LNG consumption by approximately 1.1 million tons and strengthen supply stability during peak demand periods.
Power Procurement Risk
Tokyo Electric Power Company Holdings announced in April that electricity supply and demand conditions during the summer were expected to remain stable in the Tokyo region, supported in part by the restart of Kashiwazaki-Kariwa Unit 6. In Kyushu, significant renewable energy surplus capacity remains available. Nuclear power plants in the region have at times faced output curtailment due to excess generation capacity. As a result, Japan’s overall electricity supply is expected to remain relatively stable. However, rising fuel procurement costs are increasingly feeding into wholesale electricity prices and retail electricity rates.
Policy Response
The Japanese government has worked closely with oil companies to secure alternative procurement routes while avoiding reductions in domestic consumption. As a result, approximately 60 percent of crude oil imports in May and more than 70 percent in June were secured through routes that did not pass through the Strait of Hormuz, with the remainder covered through releases from the national petroleum reserves. The government has indicated that it expects to secure the oil necessary through early 2027, and therefore future releases from government reserves are expected to become more limited. In addition, subsidy measures to keep domestic gasoline retail prices at around JPY 170 ($1.07) per liter have continued since March.
At the same time, diversification of procurement sources has become an important medium- to long-term policy priority. The government is moving to diversify procurement across North America, Latin America, Central Asia, Southeast Asia, the Middle East and Africa. It is also considering expanded provision of risk capital to strengthen upstream, midstream, and downstream supply chain operations.
In parallel, the government is accelerating the deployment of next-generation energy technologies. Greater emphasis is now being placed on perovskite solar cells, hydrogen, ammonia, biofuels, geothermal power and carbon capture and storage. These technologies are increasingly viewed as important not only for decarbonization but also for strengthening energy security.
Looking Ahead
Energy security is expected to become a major political and policy priority in Japan. The Iran crisis and risks surrounding the Strait of Hormuz are likely to accelerate discussions on diversification of crude oil procurement, expanded use of nuclear power, greater renewable energy deployment and commercialization of next-generation energy technologies.
Korea
| Korea Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 28.1% | 99.5% |
| Oil | 0.2% | 100% |
| Coal | 28.1% | 100% |
| Nuclear | 31% | 100% (enriched uranium) |
| Hydro | – | – |
| Solar | 6.2% | – |
| Wind | 0.6% | – |
| Geothermal | – | – |
| Others | – | – |
| Korea Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026* | Government Subsidy (yes/no/partial) |
| Household | KRW 214/kWh ($0.14/kWh) | KRW 214/kWh ($0.14/kWh; price frozen) | Partial (for the socially vulnerable) |
| Low/Medium Intensity Commercial | KRW 110 /kWh ($0.07/kWh) | KRW 70/kWh ($0.05/kWh) | No |
| High Intensity Commercial/Industry | KRW 125/kWh ($0.08/kWh) | KRW 123/kWh ($0.08/kWh) (Daytime Discount Applied under restructured billing system effective April 16) | No |
*The price decrease in May is due to KEPCO’s seasonal tariff system, which offers lower rates during the spring season (March-May) when national power demand is low.
Market Situation
Korea remains structurally exposed to global energy disruptions because it relies heavily on imported primary energy. Most crude oil imports come from the Middle East, and a meaningful share of LNG supply is also linked to the region. Still, immediate electricity-supply risk is limited because nuclear and coal provide substantial baseload generation. The more immediate vulnerability is fuel-price volatility, because LNG continues to play an important role in marginal and peak power generation.
Power Procurement Risk
The main risk from a prolonged Iran conflict is tighter LNG markets and higher marginal fuel costs rather than an immediate supply shortfall. Korea generated about 28 percent of its electricity from LNG in 2024, leaving wholesale prices sensitive to gas-price swings. Industrial users remain the most exposed to higher electricity costs, especially energy-intensive sectors such as semiconductors, batteries, electric vehicle supply chains and data centers. Continued fuel-cost pressure could also weigh on the finances of Korea Electric Power Corp. (KEPCO), particularly while broader tariff pass-through remains constrained.
Policy Response
Korea’s policy stance continues to prioritize price stability over immediate cost recovery. Households remain partly shielded because regulated tariffs limit the near-term pass-through of higher fuel costs, while industrial users face greater exposure. In April 2026, the government revised time-of-use tariffs for large industrial users by lowering daytime rates and raising evening rates to better reflect solar output patterns and reduce reliance on LNG-fired generation during peak evening demand. More broadly, the crisis is reinforcing efforts to expand renewables, extend nuclear capacity and invest in grid flexibility and storage.
Looking Ahead
The crisis reinforces nuclear and renewables as long-term pillars of Korea’s power strategy, while LNG remains important for system flexibility in the medium term. Policy is increasingly focused on diversification, transmission expansion and lowering exposure to geopolitical fuel chokepoints. Structural power demand is also rising, driven by AI, data centers, semiconductors and broader electrification under the 11th Basic Plan.
Malaysia
| Malaysia Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 47.7% | ~80-85% |
| Diesel/Oil | – | – |
| Coal | 43.7% | 100% |
| Nuclear | – | – |
| Hydro | 3.0% | 0% |
| Solar | 4.7% | 0% |
| Wind | – | – |
| Geothermal | – | – |
| Others | 0.9% | N/A |
| Malaysia Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | Low-Usage Households (up to 1,500 kWh/month): MYR 0.24 ($0.06)/kWh Low-Usage Households Time-of-Use: MYR 0.26 ($0.07)/kWh peak, MYR 0.22 ($0.06)/kWh off-peak High-Usage Households (beyond 1,500 kWh/month): MYR 0.34 ($0.08)/kWh High-Usage Households Time-of-Use: MYR 0.36 ($0.09)/kWh peak, MYR 0.32 ($0.08)/kWh off-peak | Low-Usage Households (up to 1,500 kWh/month): MYR 0.28 ($0.07)/kWh Low-Usage Households Time-of-Use: MYR 0.30 ($0.08)/kWh peak, MYR 0.26 ($0.07)/kWh off-peak High-Usage Households (beyond 1,500 kWh/month): MYR 0.38 ($0.10)/kWh High-Usage Households Time-of-Use: MYR 0.40 ($0.10)/kWh peak, MYR 0.36 ($0.09)/kWh off-peak | Partial, for low-usage households – waiver on AFA and retail charges. Additional Energy Efficiency Incentive rebate for consumption up to 1,000 kWh. |
| Low/Medium Intensity Commercial | Low Voltage: MYR 0.24 ($0.06)/kWh Low Voltage Time-of-Use: MYR 0.26 ($0.07)/kWh peak, MYR 0.22 ($0.06)/kWh off-peak Medium Voltage: MYR 0.27 ($0.07)/kWh Medium Voltage Time-of-Use: MYR 0.29 ($0.07)/kWh peak, MYR 0.24 ($0.06)/kWh off-peak | Low Voltage: MYR 0.28 ($0.07)/kWh Low Voltage Time-of-Use: MYR 0.30 ($0.08)/kWh peak, MYR 0.26 ($0.07)/kWh off-peak Medium Voltage: MYR 0.31 ($0.08)/kWh Medium Voltage Time-of-Use: MYR 0.33 ($0.08)/kWh peak, MYR 0.29 ($0.07)/kWh off-peak | Partial. Energy Efficiency Incentive rebate for consumption up to 200 kWh. |
| High Intensity Commercial/Industry | High Voltage: MYR 0.40 ($0.10)/kWh High Voltage Time-of-Use: MYR 0.42 ($0.11)/kWh peak, MYR 0.38 ($0.10)/kWh off-peak Ultra-High Voltage (Data Centers): MYR 0.52 ($0.13)/kWh Ultra-High Voltage Time-of-Use (Data Centers): MYR 0.48 ($0.12)/kWh peak, MYR 0.44 ($0.11)/kWh off-peak | High Voltage: MYR 0.44 ($0.11)/kWh High Voltage Time-of-Use: MYR 0.46 ($0.12)/kWh peak, MYR 0.42 ($0.11)/kWh off-peak Ultra-High Voltage (Data Centers): MYR 0.57 ($0.14)/kWh Ultra-High Voltage Time-of-Use (Data Centers): MYR 0.53 ($0.13)/kWh peak, MYR 0.48 ($0.12)/kWh off-peak | No. |
Market Situation
Malaysia’s power sector remains exposed to a prolonged Middle East conflict through higher global fuel and freight costs, particularly for coal and LNG. While the country still benefits from domestic gas production, its power mix remains sensitive to external price shocks.
Domestic gas supply, supported by Petroliam Nasional Berhad (PETRONAS), provides some resilience. Still, near-term risks include higher generation costs, tighter reserve margins in some periods and spillover effects on energy-intensive industries, all of which could add to inflation pressures.
Energy-intensive sectors, including semiconductors, data centers, chemicals, logistics and export manufacturing, face the greatest exposure because they depend on reliable baseload power and are sensitive to cost volatility. Data centers are especially exposed as Malaysia expands as a regional digital-infrastructure hub, where power reliability and long-term price certainty are central to investment decisions.
Households remain partly protected by subsidies and tariff design, although sustained energy-cost pressure would add to fiscal strain.
Power Procurement Risk
An extended Iran conflict would raise procurement risk across LNG, coal and downstream power markets. Disruption around the Strait of Hormuz could tighten LNG availability and intensify competition among Asian buyers, lifting fuel costs for Malaysia’s gas-fired fleet. Coal procurement could also face higher shipping and insurance costs, pressuring utility margins and increasing pass-through risk.
Malaysia is better positioned than fully import-dependent peers because of domestic gas production. Even so, rising industrial demand and expanding digital infrastructure are increasing pressure on supply security. Businesses could therefore face higher electricity costs, tighter access to renewable supply and stronger competition for long-term power purchase arrangements.
Malaysia is unlikely to impose outright power export restrictions or export levies in the near term. If supply conditions worsen materially, however, policymakers may place domestic grid reliability and energy security ahead of broader regional export ambitions under the ASEAN Power Grid framework.
Policy Response
The government’s immediate priority is to protect supply continuity while containing domestic price pressure. Key measures include coordinated fuel procurement with PETRONAS, diversification of import sources, closer supply-chain monitoring and stronger enforcement against subsidy leakages and smuggling.
Malaysia continues to rely on targeted fuel and electricity subsidies to support households and selected sectors. But rising subsidy commitments are adding fiscal strain and reinforcing the shift toward more targeted, efficiency-based support.
Compared with some regional markets, Malaysia offers greater near-term price stability through regulated tariffs and the Automatic Fuel Adjustment (AFA) mechanism introduced in July 2025. Even so, if global energy conditions worsen, maintaining that stability would require continued policy support, making gradual tariff normalization more likely over the medium term.
Looking Ahead
The crisis reinforces Malaysia’s strategy of treating natural gas as a transition fuel while accelerating investment in renewable energy, energy storage and grid resilience under the National Energy Transition Roadmap.
Priority areas are likely to include faster solar deployment, transmission upgrades and battery storage. Policy discussions on nuclear power are also likely to continue as part of Malaysia’s longer-term low-carbon baseload options, though it is not yet a near-term power source.
Philippines
| Philippine Power Generation Mix | ||
| Energy Source | Power Generation Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 17.4% | ~46% Imported Indigenous Natural Gas: sourced from Malampaya gas field, the country’s only indigenous source of natural gas Liquified Natural Gas (LNG): According to the Department of Energy, the Philippines sources LNG from 13 countries, including Australia, Nigeria, Equatorial Guinea, United States, Malaysia, Indonesia and Singapore. |
| Oil-Based | 0.6% | Almost 100% imported The majority of existing oil-based power plants in the Philippines use diesel as their main fuel source. |
| Coal | 56.6% | ~83% Imported Domestic Coal: Majority is sourced from Semirara Mining and Power Corporation. Imported Coal: Majority is sourced from Indonesia |
| Nuclear | N/A | The Philippines has yet to include nuclear energy in its power generation mix. The Department of Energy has set 2032 as the target year for its integration. |
| Hydro | 10.8% | – |
| Solar | 3.8% | – |
| Wind | 1.0% | – |
| Geothermal | 8.8% | – |
| Biomass | 1.1% | – |
| Philippine Energy Price* | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Residential | For residential customers consuming 0 to over 200 kWh, overall electricity rate was at PHP 13.17 ($0.21)/kWh. This includes the following components: Generation Charge: PHP 7.64 ($0.12)/kWhTransmission Charge: PHP 1.23 ($0.02)/kWh | For residential customers consuming 0 to over 200 kWh, overall electricity rate was at PHP 14.33 ($0.23)/kWh. This includes the following components: Generation Charge: PHP 8.79 ($0.14)/kWhTransmission Charge: PHP 1.41 ($0.02)/kWh | The Philippine Lifeline Rate Program is a subsidy initiative that provides discounted electricity rates to low-income and low-consuming households. Discount levels differ across distribution utilities and electric cooperatives. For example, within the Manila Electric Company (MERALCO) franchise area, eligible households consuming 0-20 kWh per month may receive up to a full discount on major electricity charges, allowing them to pay as little as PHP 20 ($0.33) per month. |
| Commercial enterprise whose contracted capacity does not exceed 5 kW | The computation of the overall electricity rate is not publicly available. However, two major components of the rate computation are as follows: Generation Charge: PHP 7.64 ($0.12) per kWhTransmission Charge: PHP 1.23 ($0.020) per kWh | The computation of the overall electricity rate is not publicly available. However, two major components of the rate computation are as follows: Generation Charge: PHP 8.79 ($0.14) per kWhTransmission Charge: PHP 1.41 ($0.023) per kWh | No |
| Commercial enterprise whose contracted capacity is between 5kw and 39kw | The computation of the overall electricity rate is not publicly available. However, two major components of the rate computation are as follows: Generation Charge: PHP 7.64 ($0.12) per kWhTransmission Charge: PHP 378.33 ($6.17) per kWh | The computation of the overall electricity rate is not publicly available. However, two major components of the rate computation are as follows: Generation Charge: PHP 8.79 ($0.14) per kWhTransmission Charge: PHP 443.50 ($7.23) per kWh | No |
*Data from MERALCO, the largest electric power distribution company in the Philippines
Market Situation
The Philippines remains relatively less exposed to direct power-generation disruption from the Iran conflict because oil-based generation accounts for less than 1 percent of the electricity mix. LNG imports are sourced mainly from outside the Middle East, while coal, which still accounts for more than half of generation, is sourced domestically and from Indonesia. The country’s main vulnerability is therefore not an immediate fuel-supply shock but higher generation costs and weaker grid reliability during periods of tight operating conditions.
To limit price spikes, the Department of Energy implemented Special Operating Guidelines starting March 26, after the Energy Regulatory Commission suspended Wholesale Electricity Spot Market operations and applied modified administered pricing. These measures prioritized renewable energy and fuel conservation while helping contain price volatility. The Independent Electricity Market Operator of the Philippines reported an average market price of PHP 5.63 ($0.09) per kWh in April.
The more immediate risk is grid reliability rather than generation shortages. Recent yellow and red alerts reflected a combination of plant outages, transmission constraints and high seasonal demand, underscoring the system’s limited flexibility during peak periods.
Power Procurement Risk
Power procurement risk is increasingly tied to grid stability rather than physical fuel shortages. Supply remains generally adequate, but prolonged outages or delayed restoration of generating units can increase reliance on spot and administered pricing and expose large commercial and industrial users to greater volatility.
Data centers, manufacturing hubs and export-oriented industries remain the most exposed because they need reliable baseload power and are highly sensitive to interruptions. The challenge is increasingly one of system flexibility and transmission resilience, not simply generation capacity.
Policy Response
Government policy has focused on cushioning consumers from higher electricity costs while preserving supply reliability and grid stability. Regulatory interventions have aimed to moderate charges and reduce the immediate pass-through of higher generation costs.
At the same time, the Department of Energy continues to prioritize lower-cost and more stable generation through its dispatch policies while maximizing available capacity during peak demand. The coal moratorium remains in effect, though projects that secured non-coverage or were sufficiently advanced before the policy took effect may proceed. The government is reviewing older coal projects and aging plants while pressing ahead with already approved capacity needed to support reliability.
The government is also accelerating renewable energy, storage and grid-integration projects to strengthen long-term reliability, flexibility and energy security.
Looking Ahead
The crisis has reinforced the Philippines’ strategy of diversifying its power mix to improve long-term reliability and resilience. The Department of Energy increasingly views indigenous natural gas, renewable energy and storage as core components of a more secure and flexible power system.
Natural gas is expected to remain important as a balancing and mid-merit source as renewable penetration rises. The Philippines is also continuing preparations for nuclear energy as part of its long-term diversification strategy, with deployment targeted in the 2030s.
Overall, the crisis has reinforced the government’s view that a broader generation mix, backed by stronger transmission and storage, is necessary to improve affordability, reliability and long-term energy security.
Singapore
| Singapore Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 93.1% | *data unavailable |
| Diesel/Oil | – | |
| Coal | 1.4% | |
| Nuclear | – | |
| Hydro | – | |
| Solar | 2.5% | |
| Wind | – | |
| Geothermal | – | |
| Others | 3% | |
| Singapore Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | SGD 0.27 SGD (US$0.21)/kWh | SGD 0.27 SGD (US$0.21)/kWh | Partial – The 2026 budget announced increased quarterly rebates tiered based on the size of the Housing and Development Board household. The next tranche will be released in July. Eligible households will also receive tiered rebates for service and conservancy charges to help offset conservancy bills. |
| Low/Medium Intensity Commercial | SGD 0.26 (US$0.20)/kWh for a 12-month contract | SGD 0.32 (US$0.25)/kWh for a 12-month contract | No |
| *Final rates varying across electricity providers depending on factors like consumption and contract duration. | |||
| High Intensity Commercial/Industry | SGD 0.26 (US$0.20)/kWh for a 12-month contract | SGD 0.32 (US$0.25)/kWh for a 12-month contract | No |
| *For larger commercial customers, pricing is typically non-public and negotiated on a case-by-case basis, with retailers offering customized quotations rather than published rates. | |||
Market Situation
Singapore remains exposed to Middle East tensions because imported natural gas generates about 95 percent of its electricity. That exposure is partly mitigated by diversified supply. Gas comes from global LNG sources and from pipelines linked to Malaysia and Indonesia, reducing reliance on any single supplier. Singapore’s central gas entity, GasCo, has also secured enough LNG to meet demand through the rest of the year while pursuing additional long-term supply agreements.
The primary risk is price rather than physical availability. Singapore’s market-based electricity system transmits global fuel costs into domestic tariffs. For April-June, the regulated household tariff rose by SGD 0.56 (US$0.44) per kWh to SGD 0.27 (US$0.21) per kWh before the Goods and Services Tax, and authorities have warned that further increases are possible if geopolitical tensions persist.
Power Procurement Risk
Despite its diversified import base, Singapore continues to hedge against tighter supply and higher prices. It has not introduced export restrictions or rationing measures. The greater risk is sustained fuel-cost volatility, which can affect refiners, suppliers and large power users even when physical supply remains adequate.
Policy Response
The conflict has accelerated Singapore’s energy resilience agenda. Singapore and New Zealand signed the world’s first legally binding bilateral agreement on trade in essential supplies May 4, committing both governments to avoid unnecessary export restrictions on critical goods, including fuel, during disruptions. Singapore has also substantially concluded negotiations on a similar arrangement with Australia and is discussing comparable frameworks within ASEAN. Prime Minister Lawrence Wong has called for stronger regional energy cooperation, including work on the ASEAN Petroleum Security Agreement and broader supply chain resilience measures.
Looking Ahead
Natural gas will remain the anchor of Singapore’s power mix in the near to medium term, but policy is moving toward a broader portfolio. The government plans to add three hydrogen-ready gas plants to meet future demand while preserving fuel flexibility. At the same time, Singapore is expanding its focus on imported low-carbon electricity and other emerging energy options, including nuclear. In 2027, Singapore will undergo an International Atomic Energy Agency assessment to help inform any future decision on nuclear deployment.
Taiwan
| Taiwan Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 47.8% | 99% |
| Diesel/Oil | <1% | 97–99% |
| Coal | 35.4% | 95% |
| Nuclear | 1.1% | – |
| Hydro | 1.9% | – |
| Solar | 5.5% | – |
| Wind | 4.2% | – |
| Geothermal | 1.4% | – |
| Others | <1% | – |
| Taiwan Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | Tiered residential electricity pricing: TWD 1.78-TWD 8.86 (US$0.06-US$0.28)/kWh, summer; TWD 1.78-TWD 7.03 (US$0.06-US$0.22)/kWh, non-summer | No Changes. | Yes |
| Low/Medium Intensity Commercial | Tiered commercial electricity pricing: TWD 2.71-TWD 7.43 (US$0.09-US$0.24)/kWh, summer; TWD 2.28-TWD 5.83 (US$0.07-US$0.19)/kWh, non-summer | No Changes. | Yes |
| High Intensity Commercial/Industry | High/Extra-High Voltage (Non-Summer Rate): Demand Charge: TWD 160.60-TWD 166.90 (US$5.10-US$5.30)/kW per month.Energy Charge: TWD 8.15-TWD 8.78 (US$0.26-US$0.28) peak; TWD 2.03-TWD 2.16 (US$0.07)/kWh off-peak | No Changes. | Yes |
Market Situation
Taiwan’s power sector remains highly dependent on imported fuel, with roughly half of its electricity generation relying on LNG. In response, the Ministry of Economic Affairs has expanded spot LNG procurement from non-Middle Eastern sources, including Australia, the United States, and Southeast Asia. Following the outbreak of conflict in the Middle East, Taiwan also rerouted shipments away from the Red Sea and coordinated with long-term suppliers to accelerate deliveries and redirect vessels to ensure uninterrupted domestic oil and gas supplies. At the same time, the Executive Yuan has prioritized maintaining “market order” through market intervention, including freezing electricity rates. As a result of these measures, Taiwan has already secured sufficient natural gas supplies through September and has begun advance procurement planning for the winter season. Inflation has also remained under control, with the April consumer price index at 1.7 percent, below the government’s 2 percent inflation warning threshold.
Power Procurement Risk
Strengthening LNG procurement from the United States has become both an energy policy and geopolitical priority for Taiwan. Earlier this February, CPC Corporation, Taiwan, signed a US$15 billion long-term LNG agreement with U.S. suppliers before regional tensions escalated. Deliveries are expected to begin in June, with annual imports reaching 1.2 million metric tons starting in 2027, helping reduce reliance on Middle Eastern energy sources.
A more immediate concern comes from Australia, which supplied about 33 percent of Taiwan’s LNG imports last year. Australia plans to introduce a domestic gas reservation mechanism next July, requiring exporters to reserve part of their supply for domestic use. However, contracts signed before December 22, 2025, will remain protected, and CPC Taiwan’s agreements are not expected to be affected. The Ministry of Economic Affairs has also emphasized that Taiwan can further diversify supply through increased LNG procurement from the United States and other Indo-Pacific sources.
Policy Response
The government continues to aggressively subsidize prices to absorb market shocks, prioritizing retail price stability over market-reflective pricing. From late February through May 24, the state-owned CPC Corporation absorbed TWD 15.7 billion (US$499.3 million) under the “Asian Neighbor Ceiling” and conflict-specific smoothing mechanisms. The vice premier leads a weekly Middle East Situation Task Force ensuring downstream inventory stability for plastics, medical devices, and agricultural materials. Furthermore, direct transport subsidies launched May 20 provide targeted relief to taxi operators and domestic logistics carriers, artificially stabilizing logistics costs despite high global energy inputs.
Looking Ahead
Rather than reinforcing gas as a bridge fuel, the crisis is forcing a dual acceleration toward structural diversification and political recalculations on nuclear energy. Geopolitically, Taiwan is rapidly decoupling from Persian Gulf dependence. U.S. natural gas imports jumped from 9.4 percent in 2025 to 26.2 percent in the first four months of 2026, peaking at 46.7 percent in April. Domestically, the crisis — coupled with massive AI power demands — has tilted public opinion and international alignment, accelerating a political pivot from the current administration to prepare the decommissioned NPP-2 and NPP-3 plants for restart under the justification of regional national security.
Thailand
| Thailand Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 60% | 45–50% |
| Diesel/Oil | – | – |
| Coal | 8% | 45–50% |
| Nuclear | – | – |
| Hydro | 5% | Partial import exposure from Laos |
| Solar | Part of ~12% renewable generation mix | N/A |
| Wind | N/A | |
| Geothermal | – | – |
| Others | 15% imported electricity/biomass/waste | Mixed |
| Thailand Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | THB 3.98-THB 4.15 ($0.12-$0.13)/kWh Thailand’s electricity bill consists of Base tariff Fuel tariff charge Value-added tax | THB 3.95-THB 4.10 ($0.12-$0.13)/kWh | Yes (partial) Government actively suppresses Ft increases for households through tariff intervention and delayed cost recovery by EGAT |
| Low/Medium Intensity Commercial | THB 4.20-THB 4.60 ($0.130-$0.14)/kWh | THB 4.30-THB 4.75 ($0.13-$0.15)/kWh | Partial Commercial users receive indirect protection because tariff increases are politically moderated, but still face meaningful fuel tariff pass-through |
| High Intensity Commercial/Industry | THB 4.50-THB 5.20 ($0.14-$0.16)/kWh | THB 4.70-THB 5.50 ($0.15-$0.17)/kWh | Limited / No Large industrial users are more exposed to actual fuel costs and Ft adjustments, with limited political shielding compared to households |
Market Situation
Thailand’s power sector remains exposed to imported fuel volatility because natural gas continues to dominate generation in the Electricity Generating Authority of Thailand (EGAT) system. Declining domestic gas output has increased reliance on imported LNG, heightening exposure to global spot-market swings and shipping disruptions linked to the Iran conflict. Imported electricity also remains an important part of supply, reinforcing Thailand’s dependence on regional and cross-border stability.
The near-term risk is higher fuel costs rather than physical shortages. Thailand still has diversified LNG procurement channels and adequate reserve margins, limiting immediate blackout risk. However, rising LNG and oil prices continue to pressure the fuel tariff and lift electricity costs across the system. Industrial users, particularly data centers, electronics manufacturers, petrochemical producers and exporters, remain the most exposed because government intervention still prioritizes shielding households over large commercial customers.
Power Procurement Risk
A prolonged or escalated Iran conflict would affect Thailand mainly through tighter LNG markets, higher shipping premiums and stronger competition for cargoes in Asia. Because gas-fired generation underpins Thailand’s electricity system, procurement risk is concentrated in fuel affordability more than generation availability.
EGAT may face growing pressure to absorb higher fuel costs before passing them through in future fuel tariff adjustments. Large industrial users therefore face rising exposure to electricity-price volatility over time. Thailand is unlikely to restrict electricity exports because it is structurally import-reliant rather than export-oriented. Policy remains focused on preserving domestic affordability and reserve-margin stability.
Policy Response
Thailand continues to manage electricity affordability through political intervention in fuel tariff adjustments and delayed cost recovery. Households receive the strongest tariff protection, while commercial and industrial users face progressively greater exposure to fuel-cost pass-through.
At the same time, the government continues to support renewable expansion, rooftop solar liberalization and grid modernization to reduce long-term LNG dependence. Still, authorities remain cautious about allowing full price pass-through because sharp tariff increases could worsen inflation, household cost-of-living pressures and industrial competitiveness concerns. As a result, the government continues to rely on fuel tariff management, delayed EGAT cost recovery and selective tariff support to moderate electricity prices.
Looking Ahead
The crisis is reinforcing natural gas as a transition stabilizer rather than accelerating a rapid move away from gas. Policymakers increasingly view domestic gas, LNG diversification and imported electricity as necessary to preserve energy security and industrial competitiveness while renewable capacity expands gradually.
Thailand is expected to keep accelerating solar, battery storage and smart-grid development under the Power Development Plan and Alternative Energy Development Plan frameworks. But renewables remain insufficient in the near term to replace gas in providing baseload power and grid stability.
This matters because Thailand’s electricity market is increasingly defined by a dual objective: preserving affordability while strengthening long-term energy resilience. That points to continued government intervention in power pricing, alongside growing incentives for industrial users to pursue private renewable procurement and broader energy-diversification strategies.
Vietnam
| Vietnam Energy Mix | ||
| Energy Source | Energy Mix (% of total generation) | Energy Source Import Share (% of source consumed) |
| Natural Gas | 8.5% | 22.6% |
| Diesel/Oil | <1% | N/A |
| Coal | 32.1% | 43% |
| Nuclear | – | – |
| Hydro | 29.1% | – |
| Solar | 10.6% | – |
| Wind | 7.1% | – |
| Geothermal | – | – |
| Others | 12.6% | N/A |
| Vietnam Energy Price | |||
| Type of Consumers | Power Price in February 2026 | Power Price in May 2026 | Government Subsidy (yes/no/partial) |
| Household | Depending on the consumption level, with six pricing blocks. The highest is VND 3,460 ($0.13)/kWh, and the lowest is VND 1,984 ($0.08)/kWh | No changes since May 2025 | The government provided subsidies to poor household consumer and social policy beneficiaries an equivalent of VND 58,410 ($2.20) per month (equal to the cost of 30 kWh of electricity) |
| Low/Medium Intensity Commercial | Depending on the consumption level and time of use, with three blocks and three time components (normal hour, off-peak hour and peak hour), ranging from VND 5,422 ($0.21)/kWh to VND 1,609 ($0.06) ($6.10)/kWh | No changes since May 2025 | No direct subsidy |
| High Intensity Commercial/Industry | Depending on the consumption level and time of use, with four blocks and three time components (normal hour, off-peak hour and peak hour), ranging from VND 3,640 ($0.14)/kWh to VND 1,146 ($0.04)/kWh | No changes since May 2025 | No direct subsidy |
Market Situation
Vietnam’s power system is under pressure from ongoing heat waves, which have pushed electricity demand to record highs in recent months. Peak demand reached 54.6 GW on May 15. At the end of 2025, total installed capacity stood at 87.7 GW, led by coal-fired power at 32.1 percent and hydropower at 29.1 percent, followed by gas and renewable sources.
Despite these pressures, the Iran conflict is likely to have only a limited near- to medium-term effect on Vietnam’s electricity supply.
Coal remains the main source of power generation, typically accounting for more than half of daily output. Of roughly 30 GW of coal-fired capacity, about 43 percent depends on imported coal sourced mainly from Indonesia, Australia and Russia rather than the Middle East. Import volumes rose about 3.6 percent year over year in the first two months of 2026, but average prices remained below 2024 levels.
LNG is more exposed to global price swings because it is tied to international benchmarks. Still, LNG-to-power projects account for only about 2 percent of Vietnam’s installed power capacity, limiting the overall effect on the system.
Even if fuel costs rise further, the effect on end-user electricity prices is not immediate. Vietnam’s electricity sector remains highly regulated and vertically integrated, with retail tariffs administered by the government. Tariffs are usually adjusted annually or biennially, though changes can be deferred in exceptional circumstances. In practice, short-term cost increases are often absorbed by state-owned Vietnam Electricity (EVN), rather than passed directly to consumers.
Power Procurement Risk
A prolonged conflict is unlikely to materially tighten Vietnam’s fuel supply for power generation because most coal imports come from outside the Middle East, and the country has begun diversifying LNG supply sources. The bigger risk is price. Higher import costs linked to global benchmarks could further erode the economics of thermal power projects and weigh on EVN’s finances. EVN has already identified LNG-fired generation as one of the system’s most expensive dispatched sources.
Vietnam does not currently impose specific restrictions on electricity exports. Cross-border trade remains small relative to domestic supply. In the first quarter of 2026, electricity imports reached 2.9 billion kWh, or 3.8 percent of total system output, with most imports coming from Laos and China.
Policy Response
Vietnam has long relied on implicit cross-subsidies among customer groups and on retail pricing that is only loosely responsive to market conditions. That structure provides limited incentives to curb consumption and has contributed to broader energy inefficiency.
The government appears to be seeking a more balanced approach that preserves affordability while improving the financial sustainability of EVN, which has reported recurring losses in recent years.
Looking Ahead
The crisis does not reduce the importance of coal and gas as baseload and balancing fuels in the near term. At the same time, Vietnam is accelerating development of nuclear power, renewable energy and storage.
To reduce the risk of shortages during peak-demand periods, the Ministry of Industry and Trade has directed faster deployment of projects that can be implemented quickly. These include self-consumption rooftop solar, with a target of annual installations across public offices and households under the prime minister’s directive, as well as utility-scale solar and floating solar projects on hydropower reservoirs.
Overall, Vietnam’s policy direction points to three priorities: large-scale projects, especially nuclear; LNG and offshore wind; behind-the-meter and non-grid-connected renewables such as rooftop solar; and hybrid systems, including floating solar and renewables paired with storage. The government is also reviewing progress under the revised National Power Development Plan VIII, with scope to replace projects or power sources that fall behind schedule.
