Bangladesh's lights run on fossil fuels — and the gas that powered them is giving way to costlier coal and imports

Introduction

Bangladesh has largely solved the problem of reaching homes with electricity; the harder question is what that electricity is made from. In 2024, 97.7% of the country’s electricity generation came from oil, gas and coal, according to International Energy Agency data compiled by the World Bank.¹ The share was 88.6% in 1990. Over three and a half decades, dependence on fossil fuels has deepened, not eased.

48.5%

Net energy imports as a share of total energy use in Bangladesh, 2024 — up from 19.8% in 2014.

This article looks at three linked trends: rising demand, a changing fuel mix, and growing reliance on imported energy. It does not cover household cooking fuels or transport, only the power sector and overall energy balance.

Demand has grown almost fourfold in two decades

Electricity use per person rose from 46 kWh in 1990 to 169 kWh in 2005 and 632 kWh in 2024.² That is 3.7 times the 2005 level. The only dip in the series came in 2020 (512 kWh, from 514 kWh in 2019), the year of pandemic lockdowns, and growth resumed the next year.

Even at 632 kWh, use per person is modest, and if it keeps rising, each additional kilowatt-hour will come from whatever fuel the system relies on, which makes the fuel mix a central policy question.

Gas is losing ground, and coal is filling the gap

Natural gas, produced mostly at home, supplied about nine-tenths of Bangladesh’s electricity for a decade: 88.7% in 2000 and a peak of 92.5% in 2010.³ By 2024 its share had fallen to 65.3%. Coal, which supplied nothing before 2005, provided 1.5% of electricity in 2019, 5.6% in 2021 and 20.0% in 2024.⁴ Oil fluctuated more: 3.6% in 2010, a peak of 25.3% in 2022, then 12.3% in 2024.⁵

These shares describe what fed the grid, not why. The data coincide with the pattern one would expect if domestic gas supply struggled to keep up with demand and other fuels were brought in to cover the difference, but the IEA series itself does not give reasons. Whatever the cause, the shift moves the system away from natural gas and towards coal, the more carbon-intensive fuel.

Renewables remain marginal. Hydropower supplied 0.9% of electricity in 2024.⁶ The IEEFA, an energy-finance research institute, put renewables including hydro at 2.3% of grid-based generation in its 2026 report, against a global average of about 33.8%.⁷

Imports now meet nearly half of energy needs

Net energy imports were 17.7% of energy use in 2000 and 19.8% in 2014. They then rose steadily to 31.9% in 2019, 41.5% in 2021 and 48.5% in 2024.⁸ The path coincides in time with the fall in gas’s share and the rise of coal and oil in the power mix.

The IEEFA’s Fostering Bangladesh’s energy transition (reported May 2026) uses a different measure, primary energy imports, and finds import dependence rose from 47.7% to 62.5% over the four fiscal years from 2020-21 to 2024-25. It reports a rise of 83% in power generation costs over the same period.⁷ The two figures are not comparable: the World Bank/IEA series is net imports as a share of energy use, while the IEEFA measure covers imports of primary energy. Both point in the same direction.

Why cost, not only fuel, is the issue

The same report identifies how the system’s design adds to the bill. Capacity payments, which are fixed fees paid to private plants whether or not they run, were about BDT 9.5 per kWh for private oil-fired plants and BDT 5.9 per kWh for private coal-fired plants in 2024-25. Plants running at under 25% of capacity generated power at BDT 16.85 per kWh; plants near 75% did so at BDT 6 per kWh. The utility’s revenue shortfall in 2024-25 was BDT 556.6 billion. The report also estimated LNG import subsidies of US$1.07 billion for April–June 2026 at a price of around US$20 per million British thermal units, a projection that depends on import prices.⁷

These are findings from one research institute, reported by a news outlet; they should be read as an informed estimate rather than official accounts, and the underlying report is the place to check method and definitions.

What it will take

Evidence from the series above and the IEEFA analysis points to several options, which are for policymakers and the Bangladesh Power Development Board to weigh:

• Plan around utilisation, not only capacity. Where plants run far below capacity, fixed payments push up the cost of each unit; renegotiating or retiring the least-used capacity would lower unit costs.
• Diversify away from imported fuels. The IEEFA identifies rooftop solar and regional hydropower imports (up to 6,000 MW from Nepal and Bhutan after 2030) as options that would reduce fuel imports; both need grid investment and cross-border agreements.
• Protect efficiency gains. Industrial electricity use rose 4.8% in 2024-25;⁷ efficiency standards for factories are among the cheapest ways to hold down demand growth.
• Publish plant-level cost and dispatch data so that the public and Parliament can see what each unit of power costs and who is paid for it.
• Track emissions alongside costs. A growing coal share raises the carbon intensity of every kilowatt-hour; this should be reported with the fuel mix.