Bangladesh Faces LNG Subsidy Above Tk 60 per Cubic Metre as Asian Gas Projects Stall

Expensive imports put Bangladesh's energy budget under pressure

Bangladesh needs to provide more than Tk 60 in subsidy for every cubic metre of gas when imported liquefied natural gas costs US$20 per million British thermal units, according to an Institute for Energy Economics and Financial Analysis assessment released on November 5, 2026. Supply disruptions forced the country to buy LNG at even higher prices at times during 2026, adding pressure to public finances while gas shortages continued.

The findings place Bangladesh's subsidy problem within a wider investment slowdown. Across Bangladesh, the Philippines, Vietnam and Thailand, 49 proposed gas power plants and 22 LNG import terminal projects were cancelled, withdrawn or inactive between 2021 and 2026. Their estimated combined investment value was US$67.8 billion.

IEEFA's five-year project review, written by Sam Reynolds and Christopher Doleman, examined 92 proposed power plants valued at US$109.2 billion and 44 import terminals valued at US$21 billion. Only 11 percent of the proposed electricity generation capacity and 15 percent of the proposed terminal capacity became operational during the review period.

Bangladesh has commissioned three LNG power plants since 2021. Yet high fuel and electricity costs have increased subsidy requirements and reliance on external financing to protect foreign exchange reserves, according to the assessment. Unreliable LNG supplies have left the country facing gas shortages despite that spending.

For Bangladesh, the immediate problem is how to pay for imported fuel without putting still more pressure on the budget. For developers across the four countries, the problem starts earlier: securing equipment, financing and electricity sales agreements that can support a project through years of construction and changing fuel prices.

What the Tk 60 subsidy figure means

IEEFA's subsidy estimate connects an international purchase price with the financial support needed for gas supplied in Bangladesh. A subsidy covers part of the gap between the cost of supplying energy and the amount recovered through sales. The government absorbs that gap rather than passing the full cost directly to customers.

LNG is natural gas cooled into liquid form so that it can travel by ship. Import terminals turn it back into gas for use in power plants, factories and other facilities. The international price is commonly quoted per million British thermal units, or MMBtu, a measure of energy, while gas supplied locally can be measured by volume in cubic metres.

The more than Tk 60 figure applies at an LNG price of US$20 per MMBtu. Asian spot LNG prices reached US$27.50 per MMBtu in September 2026, 37.5 percent above that reference price. Spot purchases are cargoes bought for relatively prompt delivery rather than under a longer supply contract. IEEFA gave no corresponding subsidy estimate for the September price or a total annual subsidy forecast.

Shafiqul Alam, IEEFA's lead energy analyst for Bangladesh, described the pressure on public finances:

Rising prices of liquefied natural gas (LNG) in the international market are mounting subsidy pressure on energy sector,

Alam said price swings over the past four to five years had made both affordability and reliable supply difficult for a price sensitive importer such as Bangladesh. Higher import bills also increase the need for foreign currency, tying energy purchasing decisions to the country's efforts to preserve its reserves.

How much of the investment pipeline stalled?

IEEFA identified US$56.1 billion in proposed gas power plants that were cancelled, withdrawn or inactive, covering 49 projects with 66.2 gigawatts of capacity. A gigawatt is 1,000 megawatts, a measure of how much electricity a plant can generate at a given moment.

Another 22 regasification projects, valued at US$11.7 billion, fell into those categories. Together, they represented the capacity to handle 82 million tonnes of LNG annually. Regasification is the process of warming LNG back into gas after delivery.

The 71 affected projects accounted for about 52 percent of the 136 power plant and terminal proposals reviewed. Their US$67.8 billion combined value was also about 52 percent of the US$130.2 billion investment pipeline. IEEFA calculated that their value was nearly 4.5 times the value of projects completed during the period.

Completion was limited on both sides of the supply chain: only 15 percent of proposed terminal capacity and 11 percent of proposed power capacity opened. LNG electricity projects need fuel delivery infrastructure as well as generating equipment. Delays in either can leave the other waiting for the supplies or customers it needs.

Five years of outcomes, with longer waits to open

IEEFA's review updates an assessment published in 2021 that examined seven Asian markets and identified economic, financial, infrastructure and policy constraints. The new study concentrates on four countries expected to contribute to growth in LNG demand.

The main dates show how the investment plans developed alongside rising costs:

• 2021: IEEFA published its earlier regional assessment, providing the starting point for the new review.
• 2021 to 2026: Bangladesh commissioned three LNG power plants, while only one LNG power project reached commercial operation in Vietnam.
• Since 2022: Capital costs for recent gas projects in the United States nearly quadrupled, illustrating pressure in the wider equipment and construction market.
• September 2026: Asian spot LNG prices reached US$27.50 per MMBtu, nearly three times the pre-conflict level cited in the assessment.
• November 5, 2026: IEEFA published its review of project outcomes across the four countries.

Completed power plants took more than seven years on average from their first public development announcement to commissioning. Developers generally projected three to four years. The observed average was therefore more than three years longer than even the upper end of that usual projection.

Those waits matter for electricity planning. A plant expected to supply power within four years may arrive much later, while the cost of its equipment, imported fuel and financing changes along the way. Project schedules determine when spending can begin producing electricity and revenue.

Why the cost of LNG electricity could more than double

IEEFA estimates that higher fuel and equipment costs, combined with weaker local currencies, could raise the lifetime levelised cost of LNG electricity to 2.3 times the 2021 baseline. That is an increase of up to 130 percent.

Levelised cost is an estimate of the average cost of producing a unit of electricity over a plant's operating life. It brings together construction, financing, fuel and operating expenses. If the original estimate were represented by 100, a rise of 130 percent would bring it to 230.

Christopher Doleman, an IEEFA Asia LNG and gas specialist and a co-author of the review, said many regional energy plans had assumed relatively low fuel prices and affordable capital. The combination of cost increases now threatens the financial case on which those projects were planned.

Currency depreciation adds another pressure. When a local currency loses value against the US dollar, buyers need more local money to pay the same dollar invoice for LNG or imported equipment. A project can therefore become more expensive locally even when its dollar price stays unchanged.

Gas turbine shortages are extending delivery times for heavy equipment to six years or more. Recent US gas projects have faced capital costs nearly four times their 2022 level. For Asian developers competing in the same equipment market, shortages create uncertainty over both construction budgets and opening dates.

Why lenders need dependable electricity buyers

Sam Reynolds, IEEFA's Asia LNG and gas research lead and a co-author of the report, said volatility in fuel, equipment and currency markets had increased the risk of projects failing to proceed as planned. Less certain revenue has also made financing harder to secure.

Many large energy developments depend on non-recourse project financing. In simple terms, lenders expect repayment mainly from the project's own income and assets, rather than a broad guarantee covering the developer's other businesses. They need confidence that electricity sales will cover operating costs and debt repayments.

A power purchase agreement sets the terms under which a buyer takes electricity from a plant. A bankable agreement is one lenders consider dependable enough to support a loan. When fuel costs can jump sharply, developers, buyers and regulators must settle how those increases will be paid for.

Bangladesh's subsidy burden shows the public finance side of that problem. Keeping energy affordable for users leaves the government covering more of the cost. At the project level, uncertainty over who will pay can delay the contracts needed to attract lenders.

Different barriers in the Philippines, Vietnam and Thailand

The Philippines has seen several project cancellations since 2021, with developers struggling to secure bankable electricity purchase agreements with distribution utilities. Limited demand for LNG outside electricity generation has also weakened the business case for new import terminals.

Renewable energy expansion adds uncertainty over how often Philippine gas plants will be called on to generate. A plant operating for fewer hours has less electricity to sell, which affects the revenue available to recover construction costs and repay loans.

Vietnam has ambitious LNG electricity targets, yet only one project reached commercial operation over the five years reviewed. Uncertainty over power purchase agreements, rising LNG prices and the recovery of costs through electricity tariffs have discouraged investment. The assessment also identified concerns about the financial health of the state electricity utility.

Thailand has made comparatively greater progress in developing gas power projects. A substantial share of existing gas plant and LNG terminal capacity nevertheless remains underused. Its experience adds another concern to the delays elsewhere: completed infrastructure still needs enough demand to support its operation.

Bangladesh's options extend beyond importing more gas

Alam recommended making greater use of Bangladesh's untapped domestic gas resources, improving energy efficiency and expanding renewable energy at scale. His proposals address both the source of energy and how much consumers need to use.

Domestic gas would reduce dependence on imported cargoes, while efficiency improvements would lower the amount of fuel needed for the same industrial output or energy service. The recommendations also include greater attention to demand side electrification, meaning replacing some equipment that burns fuel directly with equipment powered by electricity.

Industries could, for example, replace gas boilers with efficient heat pumps. A heat pump uses electricity to move heat rather than producing all its heat by burning fuel. Alam identified that switch as a way to reduce industrial gas consumption and improve efficiency.

Falling solar and wind costs, shorter delivery times and growing battery storage capacity are also changing the alternatives to LNG generation. The assessment argues that these developments can reduce the need for gas plants both to supply electricity regularly and to meet periods of peak demand.

Bangladesh's three new LNG plants show that projects can reach operation. Its continuing shortages and rising subsidies show why the next decisions must account for fuel supply, operating costs and demand alongside construction. Across the four countries, IEEFA's central finding is that actual project delivery has fallen far short of expectations for rapid LNG growth.

Key Points

• IEEFA estimates Bangladesh needs more than Tk 60 in subsidy per cubic metre of gas when imported LNG costs US$20 per MMBtu.
• Asian spot LNG prices reached US$27.50 per MMBtu in September 2026, above the price used for that subsidy estimate.
• Across four countries, 49 power plants and 22 LNG terminal projects valued at US$67.8 billion were cancelled, withdrawn or inactive between 2021 and 2026.
• Only 11 percent of proposed power capacity and 15 percent of proposed terminal capacity became operational.
• Completed power plants took more than seven years on average to open, against typical projections of three to four years.
• IEEFA estimates LNG electricity costs could rise by up to 130 percent against 2021 baselines and recommends domestic gas, efficiency, renewable energy and greater electrification for Bangladesh.