It is unclear if LNG imports can guarantee Southeast Asia’s energy security

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Key points:

  • ASEAN members plan to import more LNG, including as part of tariff negotiations with the Trump administration. 
  • Southeast Asian countries are planning LNG import infrastructure investments that will cost an estimated USD 11.8 billion.
  • As a fuel that must be continuously imported, LNG has a mixed record in delivering energy security in ASEAN because it can become unaffordable or supply can be disrupted.
  • Asia now has to live with the risk of LNG price volatility and sudden surges in demand from Europe. In recent years traders have diverted LNG cargoes from Asia towards Europe because they can obtain higher profits, and this trend is likely to continue if European demand for LNG remains high. 
  • Southeast Asian countries have alternatives to importing LNG that can increase their energy independence and resilience. 
  • Options include investing in the ASEAN Power Grid and using President Trump’s recent tariffs on solar panels on Southeast Asian countries as an opportunity to direct their clean energy manufacturing base to installing more domestic renewable energy.

LNG’s promise of energy security in ASEAN

Momentum is growing behind the narrative that importing more LNG, including from the United States, is a crucial way to strengthen energy security in Southeast Asia. Japan has been promoting LNG as one option to enhance energy security and reduce emissions as part of its Asia Zero Emission Community (AZEC) initiative. One justification given by proponents of increasing LNG use in Southeast Asia is that it reduces dependence on specific energy suppliers or transit routes, thereby building supply resilience. 

The energy security narrative is driven in part by the impending growth in global LNG supplies, which is projected to increase as the United States and Qatar, in particular, expand their export infrastructure. International Energy Agency (IEA) data shows cumulative liquefaction export capacity growing 33% between 2024 and 2028, from 665 billion cubic metres (bcm) per year to 884 bcm per year.

Countries in Southeast Asia are projected to increase their use of gas as they seek to meet growing energy demand while accelerating their switch away from coal. As part of this, they are embracing LNG with plans to invest USD 11.8 billion to increase existing import capacity. The recent introduction of extensive tariffs by the US has created an impetus for affected nations to strongly signal that they wish to buy more LNG from the US.

Current regional LNG market and country-level growth plans

Thailand is one of the region’s more established LNG importers, and in line with its Gas Plan 2040 aims to increase the share of LNG used to meet its gas needs from 31% in 2024 to around 40% by 2030. Some 41% of electricity generation is projected to be from gas power plants by the mid-2030s. As part of negotiating with US President Trump over tariffs in April 2025, Thailand said it would import an additional 1 million metric tons of US LNG in 2026, and then another 1 million metric tons over the next five years. In May 2025, state-owned oil and gas company PTT said it was ready to help by importing more LNG from the US, including from the Alaska LNG project. 

Vietnam began importing LNG in 2023. According to its power development plan it aims to generate 22,524 MW of electricity from LNG by 2030 under its recently updated plan (for comparison plans are to use up to 14,930 MW from domestic gas, 31,055 MW from coal and up to 73,416 MW from solar) and has provided guarantees to make this a reality. In addition, preferential import tariffs on LNG were lowered from 5% to 2% in May 2025. In March Vietnam signed LNG agreements with US suppliers and in May it received its first LNG shipment from Russia. 

The Philippines also started imports in 2023. In March 2025 it agreed a deal with commodities trader Vitol for 8 million tonnes over the next ten years (an estimated 103 cargoes) and is considering securing LNG from Alaska in the future. The Philippines’ reference scenario in its power development plan could see LNG imports climb from zero in 2022 to 24.3 million tonnes of oil equivalent by 2050.

Malaysia is primarily an LNG exporter. As the country reduces the use of its coal power plants, it is expected to redirect some of its LNG exports to meet domestic demand. Declining reserves could see Malaysia ramp up its LNG imports in the future. Malaysia’s state-owned energy firm Petronas has been in negotiations to purchase 1 million metric tons a year from US firm Commonwealth LNG’s facilities in Louisiana since 2024 and could reach a deal soon. 

Indonesia is also an LNG exporter in a similar position to Malaysia in that it is using more of its LNG to satisfy domestic demand. The government is pushing ahead with a programme to switch power plants from diesel to LNG – the boost in gas consumption could contribute to Indonesia becoming a net LNG importer by the 2040s. In April the country announced that it was considering new LNG imports from the US as part of negotiations over tariffs. 

As part of these plans, import capacity is projected to increase in the region. Thailand currently has the largest operational LNG import capacity at 19 million tonnes per annum (mtpa) and plans to build another terminal at Map Ta Phut that could add another 5 mtpa. Vietnam has 14 projects that would bring capacity from 1 mtpa to 19.2 mtpa. Meanwhile, the Philippines has eight projects that could increase capacity by nearly 200%, making it a regional leader with 30.2 mtpa (see Fig. 1). 

These new projects are estimated to cost USD 4.9 billion in Vietnam and USD 4.2 billion in the Philippines (see Fig. 2). If all the Southeast Asian LNG projects in development (proposed and under construction) are completed, it would give the region a total import capacity of 111 mtpa of LNG and would require a total of USD 11.8 billion of investment.

Fig. 1: Planned LNG infrastructure would create new import leaders (mtpa)


Fig. 2: Vietnam and the Philippines have the largest estimated capital expenditure for LNG import projects (US$ billion)

LNG’s mixed record of delivering energy security in ASEAN

Despite the narrative that importing LNG will strengthen energy security and the plans being enacted to increase dependence on imports, LNG has an uneven track record on meeting common indicators of energy security such as security of supply and affordability. 

The 2022 energy crisis highlighted that LNG can quickly become unaffordable, and the diversion of shipments from Asia towards Europe in recent years illustrates that it does not always arrive as planned. Price volatility of LNG in an increasingly globalised market that sees Asian and European prices highly correlated is another important factor against the argument that LNG supports energy security for ASEAN.

An updated understanding of energy security

Since its creation in the mid-1970s, following the oil crisis and the economic downturn that ensued, the IEA has defined energy security on the basis of the accessibility and affordability of supply. That is, is there sufficient supply and is its price within reach?

The world has evolved since the 1970s, and so has what is understood as energy security. As the IEA’s 2024 World Energy Outlook emphasised, “shifting market trends, evolving geopolitical uncertainties, emerging technologies, advancing clean energy transitions and growing climate change impacts are all changing what it means to have secure energy systems.” 

In its summary of the IEA-UK government-hosted Summit on the Future of Energy Security April 2025, the organisers noted that a holistic approach to energy security would emphasise the importance of clean technologies that provide “opportunities to diversify energy supply, harness domestic resources, reduce import dependency and protect billpayers from volatile fossil fuel markets”.

The consequences of relying on the fluctuating price of fossil fuels were illustrated during the energy crisis of 2021-2022 when prices for gas, coal and oil surged upwards with harsh social and economic consequences for many citizens around the world.


Past as prologue: Lessons from recent geopolitical shocks

In assessing the ability of LNG to provide energy security, it is important to understand the different ways in which it can be acquired. Long-term contracts agree a price mechanism for LNG at a set delivery schedule for between 20-25 years – in Asia this price has usually been indexed to the price of crude oil but is now sometimes linked to coal or indexed to a particular hub in the US or Asia. Historically, long-term contracts were common in the LNG trade, and substantial volumes continue to be traded this way – both globally and in Asia specifically – but there are now also more flexible options available, including short-term contracts (four years or less) and spot markets. Buying LNG on spot markets allows buyers to make more flexible purchases as needs shift, but exposes them to greater volatility. The International Group of Liquefied Natural Gas Importers (GIIGNL) refers to “true” spot volumes as those delivered within three months from the transaction date.

In light of current price trajectories, it could appear that LNG will be able to meet the IEA’s energy security indicator of affordability. In 2025, Asian LNG prices on spot markets are falling, partially in response to fears of a slowdown in global economic activity due to tariff wars. The general trend is that prices are forecast to continue falling in the next few years, which could make LNG more affordable in the region. 

However, despite falling prices, price volatility remains an issue, especially on spot markets, where sudden changes can impact affordability and availability, as sales shift to the highest bidder. Volatility-linked supply issues can also impact contract buyers.

The increased globalisation of gas markets has contributed to a stronger correlation between benchmark European gas prices (TTF) and Asian prices (JKM) since 2019. This can mean that when European gas prices increase, it can lead to rising LNG prices in Asia. If this happens at the same time as Asia needs LNG, it can then lead to higher prices in these markets.

This is what happened in 2021 and 2022 when European countries suddenly started buying up LNG from global spot markets after Russia invaded Ukraine in February 2022. The knock-on effect was that countries in Asia, notably Pakistan and Bangladesh, could not access or afford LNG. Some of Pakistan’s LNG contracts were broken by traders seeking higher profits in Europe – illustrating that even if a country has negotiated a contract, this does not guarantee the security of supply metric of energy security.

Overall, the Institute of Energy Economics Japan and the Economic Research Institute for ASEAN and East Asia – two agencies that are supportive of increased LNG use in the region – note that the 2020-2022 period was a time of increasing volatility in LNG prices and that combined with high prices, this “caused serious effects on economic development and steps towards decarbonisation” for the ASEAN region.

In Thailand, for example, more expensive LNG imports in 2022 were a driver of surging electricity prices. This period corresponds with a 28% rise in LNG imports to make up for reduced domestic and pipeline supplies. The Institute for Energy Economics and Financial Analysis (IEEFA) estimates that growing LNG imports contributed to a doubling of domestic gas prices and record electricity prices. In response, the government took several fiscal measures to help consumers facing higher electricity bills. Additionally, the power regulator did not raise tariffs until April 2022, despite increased fuel costs. Tariffs were subsequently raised by 6.4% for May-August, and by 17% for September-December, rates that did not fully cover the spike in LNG prices. The cost to the government to compensate for higher electricity prices for the first four months 2023 came to THB 75 billion (USD 2.2 billion). Since then LNG prices have fallen. But in an example of the long-term consequences of LNG price volatility, state-owned Electricity Generating Authority of Thailand (EGAT) uses a portion of current electricity bills to reimburse itself for the period of high LNG prices when it subsidised electricity.

In Singapore, the government confirmed in October 2022 that higher LNG prices contributed to a rise in electricity prices. It reported that between August 2021 and August 2022 there was a year-on-year increase of 50% for LNG contracts and 224% for spot LNG prices. The difference in these increases shows that compared to spot market purchases, long-term LNG contracts can, to some extent, better shield countries from price volatility, but not completely. 

The utility company SP Group said higher global gas prices were a factor in tariffs rising 8% (by 2.21 cents per kWh) in Q3 2022 compared to Q2. The surge in LNG prices also had a cost to public finances. The Ministry of Finance distributed USD 100 per household in compensation to help with their utility bills, as part of a USD 1.5 billion package to help citizens with rising inflation.

Currency concerns

The 2022 energy crisis also highlights that Southeast Asian countries are at a disadvantage when purchasing LNG because, as the pro-LNG Asia Natural Gas & Energy Association puts it, “these developing nations have fewer financial resources to compete for LNG”, which they note can result in energy shortages or more reliance on oil or coal. One reason for this is that LNG purchases (made on the spot market or via long-term contracts) are often made in US dollars, which is expensive for countries in the region with weaker local currencies (this also means Southeast Asian countries are especially disadvantaged compared to buyers in Europe because the euro is a stronger currency than the dollar).

In practice, this has meant a higher financial burden associated with LNG purchases. For example, depreciation of the Bangladeshi taka between December 2021 and September 2023 increased the cost of LNG imports in local currency terms, putting additional pressure on tight fiscal conditions. Meanwhile, in Thailand, the depreciation of the baht in April 2023 contributed to higher LNG costs and electricity prices for citizens. More recently, in May 2025, Vietnam faced the prospect of more expensive LNG imports, with a knock-on impact on electricity costs, because of the weakening of its currency against the US dollar on the back of the US reciprocal tariffs.

Diversion of LNG cargoes from Asia to Europe

As well as having the potential to make gas more expensive, price volatility and competition with Europe have affected the predictability of LNG shipments arriving in Asia. 

In autumn 2024, a period of low wind speeds in Europe led to a surge in demand for gas to power grids there. This contributed to pushing up European gas prices, and the resulting competition with Asia in turn lifted Asian LNG prices. However, as traders could still get higher profits from shipping to Europe, LNG flows from the US to Asia fell. In October 2024 at least four cargoes were rerouted and another seven changed course in November 2024.  

This cycle of competition-driven supply diversions repeated itself in the first quarter of 2025, when at least ten more shipments were diverted. More profitable market conditions in Europe led to a higher volume of cargoes shipped there and a reduction in imports in Asia, while also contributing to upward pressure on LNG prices in Asia.

LNG imports to Asia are predicted to fall throughout 2025 due to intense competition with Europe for flexible LNG cargoes that can, at times, command a more favourable price compared to Asian spot LNG benchmarks. In short, Asia now has to live with the risk of volatility and sudden surges in demand from Europe. 

Disruptions on shipping routes 

Gas going to an Asian destination takes a route to market that is likely to be longer and slower than in the past. Severe disruptions to LNG supply routes to Asia from the US (the world’s largest LNG producer) have been ongoing for several years, and there is no clarity about when these will be resolved.

Panama Canal: Drought reduced transit of LNG from the US to Asia through the Panama Canal, the quickest route, in 2023. It is uncertain how often these drought conditions will occur again and to what extent they would disrupt future LNG shipping to Asia, but the revenue losses in 2023 convinced the Panama Canal Authority to push forward a USD 1.6 billion plan to build a reservoir in 2027. While this backup water source could be a solution, it is not due for completion until 2032, and its construction could be slowed by resistance from local communities. 

Suez Canal: The 2023 drought at the Panama Canal forced LNG shipping companies to turn to the Suez Canal. This meant higher costs and longer travel distances, alongside disruptions due to ongoing security risks in the Red Sea linked to conflicts in the Middle East. In 2023, around 8% of global LNG shipments went through the Suez Canal. These flows fell from 32.36 million tonnes in 2023 to just 4.15 million tonnes in 2024. Despite the US and the Houthis in Yemen reaching a tentative truce in early May 2025, LNG suppliers are expected to adopt a cautious approach to restarting shipping via this route. 

Cape of Good Hope: The result of disruption via the Panama and Suez canals is that the favoured route from the US to Asia has become via the Cape of Good Hope, which adds significant time. Compared to approximately 28 days via the Panama Canal, or the 34 days via the Suez Canal, it can take around 37.5 days to go round the Cape of Good Hope, incurring higher shipping costs and using more fuel at sea. 

The Oxford Institute for Energy Studies calculates that compared to going through the Suez Canal, a tanker travelling from Texas to Hong Kong via the Cape of Good Hope would increase its round-trip time, potentially reducing the number of round-trips by 10% a year. 

Strait of Hormuz: The Strait of Hormuz has long been identified as a route that would have a significant impact on global LNG supply, as it is the only transport route for LNG from Qatar and the UAE, which together account for around a fifth of the global market. Simmering, and sometimes active, conflicts in the Middle East highlight the potential vulnerability to LNG travelling along this trade route. Modelling published in June 2025 finds that if, in the unlikely event, the strait was blocked for a year, this could remove 110 bcm of LNG supply from the Middle East, resulting in a potential price shock at European and Asian gas hubs similar to that which occurred after Russia invaded Ukraine in 2022. 

Uncertain future: European demand for LNG is the ongoing wildcard that impacts Asia’s energy security

It is difficult to predict how much LNG Europe will require. On the one hand, between 2022 and 2024 energy-efficiency measures and efforts to increase the use of renewable energy contributed to the EU reducing its gas imports by around 60 bcm. The EU calculated that if key policies (including the energy transition framework and the Action Plan for Affordable Energy) are fully implemented, this could lead to a further reduction in gas consumption of between 40 bcm and 50 bcm by 2027.

However, as Europe reinforces its search for alternatives to Russian gas (which currently makes up 19% of gas imports) the region is projected to increase LNG imports by 25% in 2025. If there is slower decarbonisation within the EU, this could mean an additional 30 bcm of LNG imports by 2030. In preparation for this influx, the EU expects its LNG capacity to grow by approximately 200 bcm by 2028. 

Ultimately, a lot hinges on if the European Commission gets approval from the European Parliament to press ahead with its May 2025 proposal to completely phase out Russian gas by 2027. If this is fully implemented it could lead to an increase in demand for LNG from the global market, and therefore competition with Asia.

If Europe does significantly increase its imports of LNG in 2025 and the next few years, this could lead to spikes in LNG prices in Asia that push up domestic gas and electricity prices for citizens and businesses in ASEAN – in summary, a repeat of the dynamic during the 2022 European energy crisis. 



Alternative power sources could provide energy security

Despite the risks to availability, affordability and volatility described above, a number of Southeast Asian countries are planning to increase LNG imports.

The question remains whether this investment is a good one for ASEAN’s long-term energy security. At a time of falling prices, LNG could be seen as an attractive option for Southeast Asian countries, but it cannot guarantee energy security in terms of offering security of supply, affordability and protection from price volatility. 

Investing in LNG-related infrastructure represents an opportunity cost in that it diverts money from developing renewable sources of power that do not face the same risks for energy security.

Renewable potential

Governments in the region understand this reality. For example, the Malaysian National Energy Transition Roadmap, published in 2023 by the Ministry of Economy, notes: “there are concerns about Malaysia’s growing dependence on fuel imports, particularly natural gas imports. Given the anticipated rise in reliance on natural gas and crude oil by 2050, there is a heightened need to focus on ensuring energy security. Moving forward, Malaysia will look to reduce this dependence on natural gas by scaling up of RE capacity and exploring potential non-carbon energy sources.”

There is huge potential for renewable energy in Southeast Asia, but the region is moving too slowly. Based on National Renewable Energy Laboratory (NREL) data, Ember finds that in 2022 ASEAN was using just 1% of its solar (30,523 GW) and wind (1,383 GW) potential. Meanwhile, Global Energy Monitor finds that plans in ASEAN for new utility-scale solar and wind projects use just 3% of its 220-GW prospective capacity, adding just 6 GW to its 28 GW of current operating capacity.

At its April 2025 Summit on the Future of Energy Security, the IEA underscored that clean technologies are helping to maximise domestic energy sources, reduce imports and shield users from fossil fuel price volatility. Therefore, Southeast Asian nations face a choice. They can either import LNG with the uncertainty that brings, or they can look towards their domestic renewable energy sources to strengthen their resilience. 

What steps could ASEAN countries take to increase their use of clean technologies to enhance energy security?

Invest in rapid and ambitious renewables generation

Vietnam shows what is possible. It raised its solar PV  capacity from 105 MW in 2018 to 17.07 GW by 2023 – more than a 16-fold increase. This boost in solar helped the country reduce its import bill. A report by Ember, Centre for Research on Energy and Clean Air (CREA) and IEEFA estimates that between January and June 2022 Vietnam avoided USD 1.7 billion that it would otherwise have spent on imports of oil, gas and coal.

Purchase cheap clean technologies from China

ASEAN members could import cheap solar, wind and battery technologies from China, the global powerhouse of clean technology, which is on their doorstep. China may also be keen to export more solar panels to Asia if it is exporting less to the US. While this would entail import dependency as technology such as solar panels would need to be purchased and replaced after around 30 years, this is a different type of exposure than that of fossil fuels, which need to be imported on a continuous basis.

Use their manufacturing base to use more renewable energy at home

Another option would be to take advantage of the clean technologies they make at home. These countries possess significant solar module manufacturing capacity – outside of China they account for over 40% of global manufacturing capacity – and cover approximately 20% of global exports. 

A new opportunity to use this capacity domestically has perhaps opened up since the Trump administration announced tariffs of up to 3,521% in April 2025 on solar panel components from Cambodia, Vietnam (395%), Thailand (375%) and Malaysia (34%). According to US Census Bureau data, in 2024 Vietnam exported 19,300 MWdc((In relation to mega watts direct current (MWdc) the IEA explains “A large majority of PV installations are grid-connected and include an inverter which converts the variable direct current (DC) output of solar modules into alternating current (AC) to be injected into the electrical grid.”)) of solar modules to the US, followed by Thailand with 13,401, Malaysia 7,594, Cambodia 4,875 and Indonesia 1,853. If governments put incentives in place and investment was found, some of these exports could instead be deployed to increase domestic energy generation within ASEAN, including potentially to expand floating solar PV.

Invest in electricity grids and storage

Alongside installing more renewable energy, complementary investments can help to successfully integrate and store the energy generated by these variable clean power sources. Measures to maximise flexibility and storage, such as pumped hydro, lithium batteries and demand-side management, could play a crucial role in ASEAN. In Thailand, BNEF analysis finds that solar energy combined with battery storage is a cheaper option compared to building a new gas or coal power plant. Such storage capacity could help maximise variable sun and wind energy, as well as reduce the need for LNG imports to back up renewables.

The rapid rise in installed solar capacity in Vietnam was slowed due to issues of grid stability and congestion but this can be overcome by upgrading national and cross-border grids.

Accelerate the ASEAN Power Grid

The ASEAN Power Grid (APG) is an ambitious group of projects that would enable the transmission of electricity throughout the region by 2045 (see Fig. 3). By sharing energy through the APG, Southeast Asian countries have the opportunity to reduce reliance on imports of volatile fossil fuels by maximising each of their respective renewable energy capacities.

By late 2024, nine out of 18 key interconnection projects were finished. These projects facilitated an estimated 266 GWh of electricity flow from Laos via Thailand and Malaysia to Singapore between June 2022 and February 2024, but to complete the APG more finance and harmonisation of regulations are needed, as well as countries to champion it. Accelerating these cross-border connections could balance peaks in demand and the variable (higher or lower) generation from renewable energy in different locations, benefiting ASEAN members as they would be able to move electricity efficiently from regions with abundant hydro, solar and wind generation capacity to major demand centres in an efficient way that strengthens collective resilience. 

Countries with more hydro generation capacity such as Laos, Vietnam and Cambodia could export to countries lacking in hydro capacity, but if hydro generation is lower due to lower rainfall they could rely on other forms of renewable energy or import from their neighbours. Future interconnections from Brunei to the Philippines have the potential to reduce electricity costs and reliance on fossil fuels, but are still in the early stages.

Fig. 3: Existing and future projects in the ASEAN Power Grid
Source: ASEAN Centre for Energy, 2023



Which future will ASEAN choose?

The unreliability of LNG raises the question about what kind of energy system is being built in ASEAN. In its 2024 World Energy Outlook the IEA made the case that: “A new energy system needs to be built to last […] one that prioritises security, resilience and flexibility”. Therefore, Southeast Asian nations face a choice. 

  • They can continue taking a step into the unknown by depending on LNG imports, despite the history and potential for future price volatility, raising doubts that it can ensure resilience and deliver on security of supply. 
  • Or, in their pursuit of enhanced resilience, security and flexibility, ASEAN countries could take steps to generate and store more of their own energy from renewable sources (taking advantage of their existing clean technology manufacturing base to do so), which they then distribute via upgraded national and cross-border electricity grids, including the APG.

The EU does not need new US LNG to replace Russian gas

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Key points:

  • European Commission President Ursula von der Leyen has suggested that the EU could replace imports of LNG from Russia with additional supplies from the US.
  • Under the EU’s current climate targets, gas supply from currently producing projects and existing contracts is set to exceed demand by 2035. Any contracts agreed now that run beyond 2035 would exacerbate the EU’s forecast gas supply glut.
  • US LNG capacity already under construction is over four times greater than the amount the EU imported from Russia in 2024. No additional LNG capacity would be needed for the EU to replace Russian LNG.
  • New US capacity that began operating in December 2024 alone is 58% more than the EU imported from Russia in 2024.
  • The EU’s gas demand is set to decline by 29% from 2024 levels by 2030, and 67% by 2040.

EU considers replacing Russian LNG with US LNG

Following the re-election of Donald Trump as US President, European Commission President Ursula von der Leyen has suggested that the EU could replace imports of liquified natural gas (LNG) from Russia with additional purchases from the US. This statement has been widely interpreted as a bargaining chip ahead of likely trade talks between the EU and the new US administration, with the additional purchases potentially used to address the trade deficit and reduce or prevent US tariffs on EU exports. The EU’s new Energy Commissioner has also pledged to develop a plan to end imports of Russian energy, primarily LNG, within his first 100 days in office.

Trump has pledged that he would reverse President Joe Biden’s pause on approvals of new LNG terminals. This would open the door to 12 LNG terminals, with a total capacity of more than 133 bcm, which are awaiting US government approval. This is equivalent to the whole of the EU’s LNG imports in 2023 and would more than double US capacity from 118 bcm currently.1All gas volume units in this briefing have been converted into billion cubic metres (bcm) for consistency, using conversion factors from the BP Statistical Review of Energy.

US LNG under construction exceeds EU imports of Russian LNG

The Biden administration’s pause on approvals for new LNG terminals only affected those that had not yet received permission from the government – it did not affect terminals and LNG expansion projects that had already been approved.

Data from the US Energy Information Administration (EIA) released in January 2025 reveals that at least 73 bcm of LNG capacity is under construction. This is over four times more than the estimated 17.1 bcm of Russian LNG the EU imported in 2024 and nearly five times the 14.9 bcm imported in 2023, according to data from Rystad Energy.

This analysis clearly shows that the US does not need to approve or build any further LNG terminals for the EU to fully replace its imports of Russian gas.

Fig. 1: Capacity of new US LNG projects is over four times greater than EU imports of Russian LNG
New US capacity started in 2024

Two new US LNG projects, Plaquemines LNG and an expansion of the Corpus Christi LNG terminal, have a combined capacity of 27.1 bcm and began operating in December 2024. These two projects alone would deliver 58% more LNG than the EU imported from Russia in 2024.

Some of the LNG production from these terminals will already have been sold under contract to buyers around the world as part of their pre-construction financing. As a result, not all of the LNG would be available for purchase by the EU.

Fig. 2: Forecast US LNG capacity and new additions

EU demand for gas and LNG is declining

The EU’s total gas demand has already peaked, declining by 13% in 2022 and 7% in 2023. Consumption has continued to fall in 2024. European energy regulators have also forecast that the EU is likely to reach peak demand for imports of LNG in 2024.

This decrease in demand is set to continue. The EU’s demand for gas is set to decline by 29% from 2024 levels by 2030, and 67% by 2040, according to the European Commission’s impact assessment for the proposed target to reduce emissions by 90% by 2040. Similarly, LNG demand would drop from over 120 bcm per year in 2024 to below 60 bcm per year before 2030, if the EU meets the targets under its REPowerEU strategy.

As a result of this declining demand, the EU could soon be facing a gas surplus. Under the EU’s current climate targets, gas supply from currently producing projects in the EU, Norway and Algeria, and existing contracts from elsewhere, is set to exceed demand by 2035.2Based on the International Energy Agency’s Announced Pledges Scenario (APS) from the World Energy Outlook 2023. After this point, the EU will need to manage its oversupply through the managed decline of existing production in producer countries and/or not taking gas under their agreed contracts. Any contracts agreed now that run beyond 2035 would be surplus to requirements and would exacerbate the EU’s forecast gas supply glut.

Fig. 3: Existing supplies set to exceed EU demand by 2035
  • 1
    All gas volume units in this briefing have been converted into billion cubic metres (bcm) for consistency, using conversion factors from the BP Statistical Review of Energy.
  • 2
    Based on the International Energy Agency’s Announced Pledges Scenario (APS) from the World Energy Outlook 2023.

European competitiveness threatened by continued imports of volatile LNG

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Key points:

  • Europe is increasingly relying on imports of liquefied natural gas (LNG) as it seeks to shift away from a reliance on Russian fossil fuels. 
  • Rising imports of LNG have coincided with higher gas price volatility in Europe. In the last five years, the volatility in European gas prices has been double the historic average. 
  • Sudden spikes in gas prices have widespread economic and social impacts because they often set electricity prices in Europe. In 2022, a surge in gas prices pushed up electricity costs for households and businesses. 
  • European demand for LNG is predicted to fall over the long-term but LNG’s growing share of imports will remain an ongoing threat to the region’s competitiveness.
  • Geopolitical tensions surrounding an unpredictable second Trump presidency and intense competition with Asia for LNG might mean more price volatility in future. 
  • However, increased domestic solar and wind electricity generation could shield European countries from LNG price volatility.

Europe eyes increased imports of LNG

LNG markets are predicted to enter a “golden era” in the next few years as the inauguration of US President Donald Trump for his second term in office is expected to lead to a surge in production and exports of LNG from the US. The International Energy Agency (IEA) expects global LNG supply to grow by almost 6% in 2025, as several large LNG projects come online. Over the next decade, surging LNG supply is expected to exceed demand, a trend that will push down LNG prices. 

Some see rising LNG supply as an opportunity for Europe. The EU has said it aims to replace Russian gas flowing through Ukraine, following the end of a transit deal in December 2024, with imports of LNG. This is part of the EU’s wider plan to phase out Russian fossil fuels following the country’s invasion of Ukraine in February 2022. 

Joining the dots: Rising LNG imports and price volatility in Europe

The European benchmark for natural gas prices, the Title Transfer Facility (TTF), has experienced a rise in volatility. The average price volatility in the last five years has been two times higher than the historical average. Between 2019-2024, the average 30 day price volatility for the TTF was 85%, compared to 39% over the period 2005-2019 (Figure 1).

While energy analysts have speculated that the TTF volatility is partly structural, Europe’s increased dependence on LNG has also been cited as a driver. LNG became the new baseload source of European gas supply in 2022 (Figure 2), making the region increasingly sensitive to the liquidity and volatility of the global LNG market. Between 2005 and 2019, LNG made up 22% of European gas imports. This jumped to 44% between 2020 and 2023, with LNG overtaking pipeline imports for the first time in 2022. A report by ex-European Central Bank President Mario Draghi on EU competitiveness highlighted that: “LNG prices are typically higher than pipeline gas on spot markets owing to liquefaction and transportation costs.”

Figure 1: TTF price volatility 2005-2024
Figure 2: European gas imports 2005-2023

One of the drivers of TTF price volatility in Europe is intense competition with Asia for LNG. Price rises in Asia have reverberated back into European prices – a trend that is expected to become more prominent in future. In early 2024, rising demand in Asia, partly due to heatwaves, lower prices and lower domestic gas production, played a role in pushing up prices in Europe. “Gas prices in Europe are likely to remain volatile for some time as the EU has to compete with the more price-sensitive China and to a lesser extent India and Thailand for LNG cargoes. This dynamic introduces greater price unpredictability, as the reliability of LNG cargoes is not guaranteed in the very short term at the most optimal price,” said Stephen Ellis, an investment strategist at Morningstar.

Europe potentially faces even more intense competition with Asia and other regions for LNG if it follows through with a pledge to end gas imports from Russia by 2027 – something the new EU energy commissioner Dan Jørgensen says he intends to do. Russia still remains a key source of LNG for the EU, despite the bloc’s efforts to diversify. The end of the Russia-Ukraine transit deal already increased gas prices in Europe at the start of January, and is expected to do the same in Asia. Gas contracts in Europe are “trading at around triple pre-crisis levels so far in 2025,” according to Bloomberg. This could be made worse by colder weather in both regions. “If Europe also experiences a colder winter, buyers in Europe would have to compete for spot LNG cargoes, which in turn would raise prices at both European and Asian price hubs, especially if fuel switching is not possible,” said the US Energy Information Administration.

High energy prices weaken European competitiveness

Persistently high energy prices are restricting the competitiveness of European industry, according to the Draghi report, which noted that “even though energy prices have fallen considerably from their peaks, EU companies still face electricity prices that are 2-3 times those in the US”. A study by Goldman Sachs Research found that the higher cost of electricity is a key driver of Europe’s lower productivity relative to the US economy. 

One of the key factors in higher electricity prices has been Europe’s reliance on gas. An IMF working paper found that: “the recent spike in wholesale electricity prices in Europe has broadly been driven by the cost of production at natural-gas power plants.” In Germany at the time of Russia’s invasion of Ukraine in 2022, “electricity prices were extremely volatile and closely connected to gas price trends“. The rise in natural gas prices contributed to widespread high wholesale electricity prices in Q2 2022 when “the highest price was €500/ MWh and the average was €186.98/ MWh“. The high electricity prices hurt some key German industries such as the automotive sector. A survey of automotive companies at the time by lobby group VDA found that 10% had production restrictions and 85% considered Germany an “internationally uncompetitive location” in terms of energy prices and supply.

The impact of gas on electricity prices was felt throughout Europe – with households and businesses1Page 46. facing high energy costs, and vulnerable, low-income households being disproportionately impacted. The Draghi report found that “at the peak of the energy crisis, natural gas was the pricesetter 63% of the time, despite making up only 20% share of the EU’s electricity mix.”

Figure 3: Price-setting technology per member state and their generation mix
Source: The future of European competitiveness: Report by Mario Draghi, 2024.

Reducing Europe’s exposure to volatile LNG will enhance its competitiveness

Researchers and analysts predict that EU demand for imported LNG will potentially reduce from 2023, as climate and energy policies such as increasing energy efficiency and expanding renewable energy sources are expected to reduce gas demand by at least 40% through 2030. The EU may be better insulated against LNG volatility in the future due to this decreased demand. However, electricity prices are frequently set by the price of gas – even if used in smaller amounts. This represents an ongoing threat to stable and affordable electricity prices, and therefore the region’s competitiveness. This interlinkage is mainly driven by the design of the EU’s electricity market. “Market rules in the power sector do not fully de-couple the price of renewable and nuclear energy from higher and more volatile fossil fuel prices, preventing end users from capturing the full benefits of clean energy in their bills,” according to the Draghi report. 

The EU plans to increase its use of domestic renewable energy in order to achieve energy independence, reduce energy costs and strengthen the bloc’s competitiveness. The shift to an electrified, renewables-based and efficient energy system would reduce the “overall exposure to fossil fuel price volatility”, according to the IEA. The transition could have a “net positive effect on energy security,” provided that investments are aligned to “address new challenges posed by the increased reliance on renewables,” the IMF said. Electrification based on low cost renewable energy could also increase European competitiveness by narrowing the gap between energy costs paid by European businesses and their competitors in different regions, according to Goldman Sachs Research. 

The Draghi report finds that: “Decarbonisation could be an opportunity for Europe, both to take the lead in new clean technologies and circularity solutions, and to shift power generation towards secure, low-cost clean energy sources in which the EU has generous natural endowments.” 

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COP28: Assessment of the Oil and Gas Decarbonization Charter

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Key Points:

  • 50 oil and gas companies signed up to the Oil and Gas Decarbonization Charter at COP28 in Dubai, including 29 nationally owned companies.
  • Under the initiative, the oil and gas companies pledged to reduce their greenhouse gas emissions. The deal is voluntary and broadly repeats previous pledges made in 2021.
  • The agreement sets targets for reducing carbon dioxide and methane emissions, but does not affect oil and gas production or emissions from consumption.
  • Notable new net zero operational emissions targets include: Bapco, KazMunaiGas, Pertamina, National Oil Company of Libya, Socar, Sonangol & YPF.
  • Major investor-owned oil companies notably absent from the Charter include Chevron, ConocoPhillips and Suncor.
  • Major nationally owned oil companies notably absent from the Charter include Kuwait Petroleum Corporation, QatarEnergy, Iraq’s State Oil Marketing Company, China’s Sinopec, CNOOC and PetroChina and the National Iranian Oil Company.

Voluntary pledges repeated

At COP28, the United Arab Emirates government and company executives launched the Oil and Gas Decarbonization Charter (OGDC), which aims to reduce the greenhouse gas pollution of 50 major oil and gas companies. Twelve of these companies are also members of the Oil and Gas Climate Initiative (OGCI) launched nearly a decade ago. The new alliance is similar in approach to the OGCI (see Table 1). Companies set their own emissions reductions plans and meeting targets is voluntary. There is no penalty for not meeting self-imposed goals, for example on the continuation of gas flaring.1Gas flaring is the process of burning the natural gas which comes out of the ground during oil drilling.

Production and Scope 3 emissions

The Decarbonization Charter, as well as previous voluntary initiatives, are not aligned with the Paris Agreement goal of limiting warming to 1.5°C. Under the agreements, companies have not set targets to reduce Scope 3 emissions, which make up 80-95% of emissions from the oil and gas industry.2Scope 1 emissions are direct emissions from sources owned or controlled by a company, Scope 2 are indirect emissions from the energy it uses, and Scope 3 includes emissions the company is indirectly responsible for in its value chain, including from the use of the products it sells. Pledges on reducing carbon intensity and methane flaring could be achieved while these firms continue levels of oil and gas production that are incompatible with climate goals. In its updated net zero scenario released in September 2023, the International Energy Agency (IEA) said “no new long-lead time upstream oil and gas fields are needed” to achieve net zero by 2050.

Table. 1: Comparison of old and new voluntary commitments to decarbonise
Source: OGDC press release, OGCI strategy, 2021.

How the charter falls short

The OGDC made several pledges related to reducing emissions and investing in energy systems. However, these fall short of what is needed to reach the Paris Agreement goals of limiting global warming to well below 2°C and pursuing efforts to limit global temperature increase to 1.5°C.

Pledge 1: Reducing emissions

Charter signatories claim to support the Paris Agreement goals and the goal of reaching net zero by 2050.

  • These goals set no short term targets, despite the IEA showing that Scope 1 and 2 emissions from oil and gas need to be reduced by 60% by 2030 to remain on track for global net zero emissions by 2050.
  • The companies do not commit to cutting back oil and gas activities under the agreement. A report from United Nations experts recommends that oil and gas companies end production, expansion of reserves and exploration for new fields in order to reach net zero emissions. It concluded that “non-state actors cannot claim to be net-zero while continuing to build or invest in new fossil fuel supply”.
  • For their goals to be meaningful, and not just pay lip service to the Paris Agreement, charter signatories must also align their lobbying efforts and leave associations that are opposed to Paris-aligned climate policies.
Pledge 2: Investment in energy systems

OGDC members pledged to invest in the energy system of the future.

  • Without any quantifiable targets, this promise is too vague to be meaningful and needs to be accompanied by a phase-out date for oil and gas production.
  • A new IEA report finds that the industry allocated just 2.5% of its capital expenditure to clean energy 2022 and that this will need to rise to 50% by 2030 in order to align with the Paris Agreement.
Pledge 3: Methane and flaring

Members pledged to achieve near zero methane emissions by 2030.

  • Intensity targets do not guarantee overall reductions in emissions if production volumes are increasing. Instead, targets should be set for absolute methane emissions reductions, in line with the 75% reduction by 2030 called for in the IEA Net Zero scenario.3The IEA’s net zero scenario provides a pathway for the global energy sector to achieve net zero carbon dioxide emissions by 2050.
  • Previous initiatives, such as the Zero Routine Flaring Initiative launched by the World Bank in 2015, failed to reduce flaring. While flaring intensity has improved as a result of decoupling from oil production, total volumes of gas flaring have not materially declined since 2010. The industry’s own efforts have also not led to sufficient reduction in flaring.

Agency of oil and gas industry

Ahead of COP28, several governments called for a phase out of fossil fuels, and this is a crucial issue at the summit taking place in Dubai. Companies often seek to get ahead of the regulatory curve. By proactively announcing the speed at which it will decarbonise, the oil and gas industry seeks to reinforce its own agency to tackle climate change. For an industry with billions in sunk investments in oil and gas wells, pipelines and refineries, this is preferable to rules imposed by governments, which it will have less control over.

  • The High Ambition Coalition – including ministers from the Marshall Islands, Tuvalu, Austria, Kenya, Spain, the Netherlands and Ethiopia – recently called for a plan, to be reflected in a negotiated decision at COP28, to accelerate renewable energy and “phase-out fossil fuel production and use”.
  • A number of countries, including Denmark and France, have made commitments to end oil and gas production as members of the Beyond Oil and Gas Initiative.
Table. 2: OGDC goals compared to signatory company pledges
Company commitments listed for the most significant OGDC signatory companies.
Source: GDCA press release, company websites: BP, Shell, Eni, ExxonMobil, Aramco, ADNOC, Bahrain Petroleum Company (Bapco), Petrobras, Petronas, Pertamina, Occidental, Ecopetrol, Equinor, Repsol, SOCAR, TotalEnergies, NNPC, PTTEP, Woodside. Accessed December 2023.
Table. 3: Selected companies with significant new net zero operational emissions targets
Full list of signatories to the Oil and Gas Decarbonization Charter from COP28 press release

Nationally-owned oil companies: ADNOC, Bapco Energies, Ecopetrol, EGAS, Equinor, GOGC, INPEX Corporation, KazMunaiGas, Mari Petroleum, Namcor, National Oil Company of Libya, Nilepet, NNPC, OGDC, OMV, ONGC, Pakistan Petroleum Limited (PPL), Pertamina, Petoro, Petrobras, Petroleum Development Oman, Petronas, PTTEP, Saudi Aramco, SNOC, SOCAR, Sonangol, Uzbekneftegaz, ZhenHua Oil, YPF.

International (privately-owned) oil companies: Azule Energy, BP, Cepsa, COSMO Energy, Crescent Petroleum, Dolphin Energy Limited, Energean Oil & Gas, Eni, EQT Corporation, Exxonmobil, ITOCHU, LUKOIL, Mitsui & Co, Oando, Occidental Petroleum, Puma Energy (Trafigura), Repsol, Shell, TotalEnergies, Woodside Energy Group.
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    Gas flaring is the process of burning the natural gas which comes out of the ground during oil drilling.
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    Scope 1 emissions are direct emissions from sources owned or controlled by a company, Scope 2 are indirect emissions from the energy it uses, and Scope 3 includes emissions the company is indirectly responsible for in its value chain, including from the use of the products it sells.
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    The IEA’s net zero scenario provides a pathway for the global energy sector to achieve net zero carbon dioxide emissions by 2050.

Bangladesh’s reliance on LNG increases heat stress, finance and energy risks

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Key points:

  • Bangladesh has increased reliance on LNG since starting imports in 2018, relying on the fuel for 22% of the country’s gas demand. Since then, Bangladesh has failed to meet its targets for increasing renewable generation, which now accounts for just 2% of the country’s electricity.
  • This reliance on imported LNG means the impacts of the current energy crisis have been acute, with widespread power cuts hitting both industrial production and the availability of air conditioning during hot weather.
  • The energy crisis is set to continue, with LNG prices forecast to remain high throughout 2023 and up to the late 2020s, with similar consequences. 
  • The global LNG industry is accelerating climate change, to which Bangladesh is highly vulnerable. 
  • Heat stress from fossil fuel expansion will have severe impacts on human health, labour productivity, income and overall economic growth of the country. 
  • Extreme weather and rising sea levels are already affecting the country and, by 2050, there could be nearly 20 million internally-displaced climate migrants.
  • Bangladesh has the potential for major expansion of renewable generation, but is not on track to increase capacity in the near-term. To provide cheaper, cleaner, more reliable power, the government of Bangladesh and international finance should prioritise scaling up renewable power.

LNG has boomed while renewables have stagnated 

Bangladesh has traditionally relied on gas as its main source of electricity generation, supplied from domestic extraction since the early 1960s. Gas made up 59% of Bangladesh’s energy supply in 2020 and fuels more than two-thirds of electricity generation. However, the country’s reserves of gas are declining, while electricity demand is increasing – in 2022, the government estimated that domestic gas supplies would last for less than 11 years.

In 2016, the government set out a plan to address this shortfall, laying out a vision for a huge growth in imports of liquified natural gas (LNG). The plan set a target of starting LNG imports in 2019 at a level that would meet 17% of the country’s gas demand, rising to 40% in 2023, 50% in 2028 and 70% in 2041.

The first stage of this vision was largely achieved, with the country signing two long-term contracts to import gas from Qatar, with LNG imports starting in the 2018/19 financial year and nearly doubling in 2020/21. In 2021, Bangladesh also started buying LNG from the spot market – where gas is bought for immediate delivery and prices are far more volatile than those bought under long-term contracts. By 2022, LNG imports accounted for 22% of the country’s total gas demand.

While the government achieved ambitious targets for increasing LNG, it was nowhere near as successful in meeting its targets for renewables. In 2008, the government set a target of meeting 10% of electricity demand with renewable sources by 2020, with similar targets included in the 2016 power plan. By 2022, renewables generated just 2% of Bangladesh’s electricity, according to analysis by the Centre for Policy Dialogue, making up just 3.75% of installed capacity.

Reliance on LNG left Bangladesh exposed to the energy crisis

The country’s increased reliance on imported LNG, combined with very low domestic renewable generation, has left Bangladesh highly vulnerable to global energy supply shocks. This risk became a reality in 2021 and 2022, when global LNG prices increased dramatically, first as Russia reduced gas exports to Europe and again following Russia’s invasion of Ukraine. 

In the year running up to the invasion, Asian LNG prices rose by 390% before rising a further 48% in the five months after the invasion – reaching a peak more than ten times higher than prices in the same month in 2020. The benchmark price for LNG averaged USD 34 per million metric British Thermal Units (MMBtu) in 2022, compared to USD 15/MMBtu in 2021. 

As well as facing significantly higher prices for LNG imports, Bangladesh also saw reductions in the LNG supplied through its long term contracts from Qatar, according to analysis by the Centre for Policy Development.

Faced with such high prices, Bangladesh stopped making spot market purchases of LNG in July 2022. As a result, the country faced widespread power cuts in the second half of the year. In mid-July, 20% of the country’s electricity demand was not met due to gas shortages, with the country cutting power on 85 of the 92 days up to the end of October, according to analysis by Reuters. At its worst point in October, blackouts affected 75%-80% of Bangladesh, leaving 130 million people without power, as a third of the country’s gas power units faced a gas supply shortage. The electricity that could be supplied also came at a huge cost – electricity generation costs rose by 47% from financial year 2020-21 to 2022.

The impacts of this on Bangladesh have been significant. Industrial production, including the garment sector, fell by a reported 25%-50%, placing further pressure on the country’s balance of payments. 

Up to a quarter of the country’s power demand comes from air conditioning, so cutting off power supplies left people – particularly older people, disabled people and children – at greater risk of heat stress, with temperatures in places exceeding 40°C. 

Bangladesh’s energy crisis is set to continue

Asian LNG importers such as Bangladesh are currently experiencing a reprieve from the record high prices of 2022, with regional prices currently lower than all of 2022 and on a par with mid-2021. In February, the country re-started purchases on the spot market with a purchase from TotalEnergies at USD 19.78/MMBtu, with the country aiming to keep purchases below USD 20/MMBtu this year.

But this drop in prices is not forecast to last. After a steep drop in 2022, Asian gas demand is expected to rise by around 3% in 2022 due to the lifting of China’s zero-Covid policy, which, combined with Europe’s increased demand for LNG, will put upward pressure on prices:

Fig. 1: Historic and forecast Asian LNG prices
Source: International Monetary Fund, S&P Global, Reuters

Global LNG prices are set to remain high at least until 2025 or 2026, when new LNG supplies are set to come onto the market. Bangladesh is reported to be looking for new long term LNG supply contracts, however there is very limited availability and competition from European buyers prepared to pay high prices. Until then, maintaining or growing Bangladesh’s recent levels of LNG imports will have to rely on expensive and highly volatile spot markets.

The impacts of such high prices on Bangladesh look set to continue. In January 2023, the government increased gas prices to commercial users by between 14% and 179% (household prices were left unchanged). This presents a significant challenge for the garment sector, which makes up more than 80% of the country’s export earnings. Producers must either pass on higher production costs to international buyers or face falling sales and profits. Power sector subsidies reached BDT 297 billion (USD 2.74 billion) in the financial year 2021-22, and are likely to rise further in 2023. It is highly likely that Bangladesh will experience further blackouts due to a shortage of LNG, with knock-on impacts on the availability of air conditioning during heatwaves and the productivity of the economy.

Despite the outlook for LNG prices, Bangladesh is planning to double its LNG import capacity with a more than 150% increase proposed, according to Global Energy Monitor (GEM). LNG imports are forecast to rise by more than 350% between 2020 and 2030, according to analysis by the Centre for Policy Development. This increase goes hand in hand with an expansion of gas power installation. The country has 11.5 GW of gas power currently installed, another 2.3 GW under construction and further 33.3 GW proposed, according to GEM.

LNG investment: Finance and stranded asset risks

Asia is expected to witness a surge in gas infrastructure investments, with the total investment in proposed projects reaching USD 379 billion. Bangladesh has one of the most extensive expansion plans, with USD 16.5 billion of investment in new gas infrastructure. This investment includes the construction of LNG terminals, pipelines and new power plants.

Table 1: Bangladesh planned investment for fossil gas infrastructure
Source: Global Energy Monitor, 2021

The reliance on gas for energy development raises concerns about the country’s large and unsustainable debt burden. Building additional gas infrastructure for the power sector, often under the guise of a ‘bridging fuel’, entails high financial risks to a developing country, particularly as the levelized costs of electricity from renewable energy are lower than for gas and will continue to fall. As the competitiveness of renewable energy prices persists, Bangladesh’s pivot toward gas will result in a poor investment and wasting valuable capital. For example, Bangladesh is reportedly currently facing a hefty debt bill of USD 2 billion every year from the power sector’s mega projects, specifically fossil fuel development. Amidst the global transition towards clean energy, gas infrastructure could potentially become stranded assets, posing a significant financial risk to Bangladesh, leading to broader and more severe socio-economic problems.

LNG expansion is accelerating climate change

While the lack of power increases the health risks from heatwaves in Bangladesh, increasing the use of LNG is also accelerating climate change, which will make extreme weather events in the country more severe and frequent.

Natural gas is the fastest growing source of CO2 emissions from fossil fuels, responsible for more than half the increase in the last five years. Worldwide, a 173% increase in LNG export capacity is in development, an expansion that puts the Paris Agreement climate goals at serious risk. The Intergovernmental Panel on Climate Change (IPCC) has found that emissions from existing and planned unabated fossil fuel infrastructure would push the world past 1.5°C of warming, unless they are phased out early.

The extraction and transportation of gas emits methane, a powerful greenhouse gas that is responsible for around a quarter of the 1.1oC of warming the world has already experienced since pre-industrial times. Transporting gas as LNG is also emissions intensive due to the energy required to super-cool the gas. In the US alone, the seven LNG terminals currently operating have the equivalent emissions to almost nine coal power stations. 

If all LNG terminals globally had the same emissions intensity as those in the US, together they would have the same emissions as 46 coal power stations, with emissions greater than Malaysia’s and the Philippines’ coal fleets combined. An analysis of multiple studies of US LNG shipped to Europe found that “emissions from the extraction, transport, liquefaction, and re-gasification of LNG can be almost equal to the emissions produced from the actual burning of the gas, effectively doubling the climate impact of each unit of energy created from gas transported overseas.

Increasing impacts of climate change

Bangladesh is widely recognised as being one of the most vulnerable countries to the impacts of climate change, largely due its natural geography on a low-lying delta with a high risk of cyclones, extreme rainfall, flooding and droughts, combined with high population density. Fifty-six per cent of the population – more than 90 million people – live in areas with a high exposure to climate change, compared to a global average of 14%. Thirty-three per cent of the population – more than 53 million people – face very high exposure to climate change, compared to just 6% globally.

These risks are not just a future possibility, but are already impacting Bangladesh. Between 2000 and 2019, the country experienced 185 extreme weather events due to climate change. Tropical cyclones are estimated to cost Bangladesh USD 1 billion annually, and around 20 million people are already having their health affected from saltwater-polluted drinking water linked to sea level rise. In 2022 alone, over 7.1 million Bangladeshis were displaced by climate change, according to the World Health Organisation.

Fig. 2: Proportion of population exposed to climate risks
Source: USAID

These impacts are set to get worse as the climate warms. The IPCC has found that wind speeds and rain rates of tropical cyclones will increase as global temperatures rise. By 2050, Bangladesh could have up to 19.9 million internal climate migrants, according to the World Bank, almost half the projected internal climate migrants for the whole of South East Asia. By 2100, one third of the population of Bangladesh could be at risk of displacement. 

The extent of these impacts will be determined by the speed at which the world can reduce greenhouse gas emissions – the science is clear that an immediate and rapid reduction in the use of gas is required to avert the worst impacts of climate change.

Impacts of heat stress due to fossil fuel and LNG expansion in Bangladesh and around the world

Bangladesh is predicted to experience more frequent and severe heatwaves, which have been shown to increase mortality rates by as much as 31.3% for every 1°C increase in the universal thermal climate index. 

Heat stress can exacerbate respiratory problems, such as asthma and chronic obstructive pulmonary disease (COPD), which are already common in Bangladesh due to air pollution. These can result in reduced productivity, increased absenteeism and long-term health issues.

Vulnerability to heat-related diseases is exceptionally high among people over 65, who often have underlying medical conditions. Children are also vulnerable to heat events, due to their susceptibility to vector-borne diseases, as are individuals with low literacy levels who may not be fully aware of the dangers of extreme heat events.

Vulnerable communities are also more likely to experience economic impacts from heat stress, such as lost wages from illness or decreased productivity. Low-income households may also struggle to pay for cooling, or live in housing without adequate ventilation or insulation, increasing the risk of heat stress and heat-related illness.

Psychological impacts of heat

Recent research has highlighted the impact of climate change on mental health in Bangladesh, revealing a link between elevated temperatures and mental health-related morbidity and mortality. A Lancet Countdown report projected deadly heat problems for densely populated areas, such as Dhaka and Chattogram, where the urban heat island effect exacerbates the vulnerability of residents. 

Vulnerability to mental health impacts is particularly acute for older populations, women, individuals with physical disabilities or illnesses, and households experiencing economic shocks. 

Heat impacting productivity at work

The warming planet will increase the health and well-being risks associated with working in hot and humid conditions. This is especially true for low and middle-income tropical countries like Bangladesh, where a significant proportion of the population are manual workers in agriculture and construction. Workers exposed to heat stress are at risk of a range of health impacts, including dehydration, heat exhaustion, heat stroke and other heat-related illnesses. 

Extreme heat exposure is also affecting working hours, resulting in a significant loss of labour. The International Labour Organization (ILO) has identified Bangladesh as one of the South Asian countries that faces a high risk of lost working hours due to heat stress, especially in the agricultural sector. At present temperatures, the country loses 254 hours of labour per person annually due to heat exposure. This figure increases significantly to 573 hours of labour loss per person annually if the temperature rises by 2°C.  

Workers are less able to perform physical tasks in high temperatures and humidity, leading to decreased output, increased downtime and reduced economic efficiency, which in turn can reduce income and economic growth. Additionally, the costs of providing medical care and preventative measures to reduce heat stress can be significant. 

Fig. 3: Heat exposure and working hours lost
Source: Parsons, L. A., Shindell, D., Tigchelaar, M., Zhang, Y., & Spector, J. T. (2021).
Table 2: Working hours lost to heat stress, by sector and country, southern Asia, 1995 and 2030 (projections)
Source: ILO, Working on a Warmer Planet (2019)

According to the ILO, heat stress caused more than 5% of GDP loss in Thailand, Cambodia, and Bangladesh in 1995. By 2030, heat stress could have a similar impact on GDP in Thailand, Cambodia, India and Pakistan. Bangladesh is projected to lose around 4.9% of its GDP to heat stress by 2030 – a potential loss of USD 95.75 billion. The significant impact of these losses on the country’s population and economy underscores the urgency of implementing measures to mitigate the effects of extreme heat on working conditions and productivity.

Renewable energy offers a better alternative

In contrast to the huge growth in LNG import capacity and gas power generation, the pipeline for renewable energy projects in Bangladesh is very limited. In its 2021 climate submission to the UN Framework Convention on Climate Change (UNFCCC), Bangladesh aimed to increase renewable energy capacity by just 0.9 GW by 2030 and only 4.1 GW if the country receives international financial support. This would lead to renewables generating just 4% of the country’s electricity by 2030. In the same submission, Bangladesh proposed increasing gas capacity by 5.6 GW with international financial support, reaching a total capacity over three times higher than that for renewables.

Fig. 4: Proposed gas and renewable capacity by 2030
Source: Bangladesh 2021 Nationally Determined Contribution submission to the UNFCCC

Unless significant policy changes are introduced, the growth in renewables in Bangladesh is set to be very limited. According to the National Solar Energy Roadmap, under a business-as-usual scenario, the country would only have 2.4 GW of solar power installed by 2030 and 6 GW by 2041, with solar making up the majority of the country’s renewable generation.

Despite the limited pipeline for new projects, Bangladesh has the potential to greatly increase the deployment of renewable energy. In 2021, the government launched the Mujib Climate Prosperity Plan (MCPP), setting out a vision of how the climate-vulnerable country could become resilient and prosperous through adapting to and mitigating climate change. The MCPP laid out different scenarios for the potential deployment of renewable energy. In the most ambitious, the country would reach a 30% share of renewable energy by 2030, with a capacity of 16GW, rising to 40% in 2040 with a capacity of 40GW. The Sustainable and Renewable Energy Development Authority (Sreda) has also reportedly proposed a target of generating 5 GW from wind power by 2030, up from virtually none today.

Renewable energy represents a far better alternative to gas to meet Bangladesh’s growing electricity demand. Renewable energy is cheaper than gas – in late 2022, the Institute for Energy Economics and Financial Analysis (IEEFA) estimated that the cost of energy from rooftop solar and utility scale solar are BDT 5.5 and BDT 7.6, well below the current average electricity generation cost of BDT 10. Worldwide, new solar is estimated to be between 11% and 40% cheaper than the cost of new gas plants. Renewable energy is also more reliable than bidding for LNG supplies in a volatile and competitive international market, where buyers in richer regions like Europe can outbid Bangladesh. 

Despite these advantages of renewable energy, the country is well off course to meet the ambitious targets in the MCPP. If the country had followed the most ambitious pathway in the MCPP for solar power deployment, Bangladesh could have reduced the volume of its spot market LNG imports by 25% between 2022 and 2024 compared to the current trajectory, saving USD 2.7 billion, according to analysis by Ember.

Fig. 5: Solar power projection and Bangladesh’s spot LNG purchases
Source: Ember

Bangladesh has now set a target of achieving 40% renewable energy by 2041, but is not currently on course to grow its share of renewable energy in the near future. Expanding LNG imports and gas power generation is set to come at a significant cost to Bangladesh, and is far from guaranteed to be able to supply reliable power to the country. The costs of these projects would be better spent supporting an immediate and rapid increase in the deployment of solar and wind power, to provide cheap reliable power to the country. International donors and financial institutions should also dramatically increase the level of financing available for renewable energy projects – between 2000 and 2020, renewables only received 17% of the USD 10.9 billion in public finance for electricity generation in Bangladesh.

In March 2023, the government of Bangladesh is expected to publish its Integrated Energy and Power Master Plan, updating the 2016 power sector plan. This review gives Bangladesh the opportunity to learn the lessons of the ongoing global gas price crisis, revise down the planned expansion of gas power and LNG imports and instead focus on rapidly scaling up wind and solar power.

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