Power Sector of Bangladesh

Bangladesh’s Power Capacity Boom: Why More Megawatts May Not Deliver Energy Security

Bangladesh has spent more than a decade trying to solve one problem: not having enough electricity-generation capacity.

By 2024, that problem looks very different. The country now has large coal plants, gas plants, oil-fired plants, imported electricity and a nuclear plant approaching operation. More generating capacity is still being added.

Yet Bangladesh continues to experience power shortages. That contradiction reveals the deeper weakness in the country's power strategy.

Bangladesh is increasingly capable of producing electricity. The harder question is whether it can reliably supply the fuel, foreign currency, transmission infrastructure and money required to operate the capacity it has built. The numbers already show the mismatch.

At the end of FY2022–23, Bangladesh had 24,911 MW of grid-connected generation capacity. Maximum generation during the year reached only 15,648 MW. BPDB's forecast peak demand was 17,100 MW.

A World Bank assessment reported in May 2023 reached a similar conclusion from another direction: power-generation assets were being utilized at below 50%, with fuel shortages, dispatch problems and transmission constraints among the causes.

Bangladesh therefore does not simply have a megawatt problem. It has an energy-

Ruppur Nuclear Power Plant 

Capacity and Actual Electricity Production Tell Different Stories

Installed capacity can be misleading because a 1,000 MW plant does not produce 1,000 MW continuously.

The plant needs fuel. It needs working transmission infrastructure. It needs to be economically dispatchable. The buyer also needs enough money and foreign exchange to pay for the electricity or fuel.

BPDB's FY2022–23 data make this distinction visible.

Energy source	Installed capacity	Share of capacity	Net generation	Share of generation
Natural gas	11,372 MW	45.7%	46,013 GWh	52.0%
Furnace oil	6,492 MW	26.1%	18,323 GWh	20.7%
Diesel/HSD	1,010 MW	4.1%	2,327 GWh	2.6%
Coal	2,692 MW	10.8%	10,081 GWh	11.4%
Power import	2,656 MW	10.7%	10,425 GWh	11.8%
Solar	459 MW	1.8%	~671 GWh	~0.8%
Hydro	230 MW	0.9%	~610 GWh	~0.7%
Total	24,911 MW	100%	88,450 GWh	100%

Source: Bangladesh Power Development Board, Annual Report 2022–23.

This generation mix also shows why Bangladesh's energy security cannot be judged from installed capacity alone.

More than half of the electricity came from gas. Another 23% came from furnace oil and diesel. Coal and imported electricity contributed another 23%.

Most of these sources ultimately expose Bangladesh to either fuel availability, foreign-exchange requirements or international commodity prices.

The Cost of Electricity Was Already Moving Up

The financial pressure is equally important.

BPDB's average total generation and purchase cost increased from Tk 8.84 per kWh in FY2021–22 to Tk 11.33 in FY2022–23, an increase of almost 33%.

The cost also varied dramatically depending on where the electricity came from.

Source or plant	FY2022–23 cost
BPDB-owned gas plants, average	Tk 5.13/kWh
Public-sector purchased power	Tk 6.85/kWh
Power imports from India, average	Tk 8.77/kWh
BPDB-owned Barapukuria coal units, combined	Tk 11.51/kWh
Rental power purchases	Tk 12.53/kWh
Adani Godda	Tk 14.02/kWh
Rampal/Maitree	Tk 14.12/kWh
IPP purchases, average	Tk 14.62/kWh
Payra 1,320 MW	Tk 16.02/kWh
BPDB-owned HFO plants, average	Tk 23.42/kWh
BPDB-owned diesel plants, average	Tk 39.72/kWh

These figures represent BPDB's FY2022–23 accounting for different plant and procurement categories. They should not be treated as identical tariff structures or direct lifetime-cost comparisons.

This is the first warning sign. Bangladesh increased capacity partly because shortage was once the country's dominant power-sector problem. But maintaining a large fleet of plants creates a second problem: someone must pay for the capacity even when much of it is not heavily utilized.

In September 2023, the state minister for power told parliament that Tk 104,926 crore had been paid over 15 years to 82 IPPs and 32 rental plants as capacity charges or rental payments. Capacity payments themselves serve a legitimate purpose: they compensate plants for remaining available when the system needs them. The financial problem becomes more serious when reserve capacity consistently exceeds demand and expensive plants remain underused.

That is exactly why future capacity planning matters.

Coal Solves One Problem but Creates Another

Bangladesh's expansion into large coal-fired baseload plants was intended partly to diversify a system historically dominated by natural gas and expensive liquid fuel.

That logic is understandable. The vulnerability lies in where the coal comes from.

Bangladesh's only operating coal mine, Barapukuria, produced about 767,308 tonnes in FY2022–23. Its entire output was supplied to the 525 MW Barapukuria power station. Meanwhile, the country imported more than 7.1 million tonnes of coal during the same year.

That imbalance becomes more important as new coal plants enter the system. Payra, Rampal, Matarbari and SS Power depend on imported coal. Adani's Godda electricity is generated in India using imported coal and sold to Bangladesh under a long-term PPA.

The result is not genuine fuel independence. It is diversification away from domestic gas into another set of import-dependent energy sources.

Payra Already Demonstrated the Foreign-Exchange Risk

The 1,320 MW Payra plant is one of the clearest examples. The technology worked. The generation capacity existed. Coal suppliers existed. Yet the entire plant stopped producing electricity in June 2023.

The reason was not a shortage of generating equipment. Bangladesh had accumulated around $390 million in unpaid coal bills amid the dollar shortage. One unit stopped on May 25 and the remaining unit shut down on June 5 after coal stocks ran out.

Payra returned after a 20-day shutdown when coal shipments resumed. This episode demonstrates an important distinction:

Installed energy capacity is not the same as usable energy capacity.

A 1,320 MW plant without financing for imported fuel temporarily becomes a 0 MW plant.

Rampal Faces the Same Fuel Exposure Plus Environmental Risk

Rampal, officially the Maitree Super Thermal Power Project, adds another 1,320 MW of coal capacity.

Its first 660 MW unit entered commercial operation in December 2022. During the following seven months, that unit was shut down six times because of a combination of coal shortages and technical problems.

That history matters because Rampal is also dependent on imported coal. The project carries another category of risk as well.

A UNESCO World Heritage Centre and IUCN monitoring mission concluded in 2016 that the plant posed a serious threat to the Sundarbans World Heritage property. Its concerns included coal-ash pollution, wastewater, shipping, dredging and the cumulative impact of industrial development. Bangladesh subsequently implemented mitigation measures and continued the project, but the controversy demonstrates that large fossil-fuel projects can face risks beyond electricity economics.

The issue is therefore not whether Rampal can generate electricity, It can. 

The issue is whether a system containing several large imported-coal plants can remain financially and operationally resilient when the same foreign-exchange constraints affect all of them.

Matarbari Is More Complicated Than Its Price Tag Suggests

Matarbari is perhaps the most interesting case.

The 1,200 MW ultra-supercritical power project eventually reached an estimated cost of about Tk 51,854.9 crore, up from roughly Tk 35,984 crore.

A major reason for the increase was the expansion of the original coal-delivery channel and related infrastructure so that the area could support a deep-sea port. The revised project expanded the channel from about 3 km to 14.3 km and substantially increased its dimensions.

That makes one common comparison misleading.

It is not accurate to treat the entire Tk 51,854 crore as the cost of constructing only a 1,200 MW power station. Part of the expenditure created port and channel infrastructure that could have wider commercial value.

But that does not remove the project's energy-sector risks.

Matarbari still requires imported coal, large external financing and long-lived coal infrastructure. JICA signed another loan of up to ¥217.556 billion for Phase 1 in September 2023.

At the same time, Japan refused to finance the proposed Matarbari Phase 2 coal expansion.

The distinction is important: Japan did not abandon Matarbari Phase 1. In June 2022, the Japanese government suspended ODA support for the proposed second phase as part of its G7 commitment to end new direct government support for unabated international coal power. Bangladesh subsequently decided not to proceed with that coal expansion. That decision points to another long-term risk.

Even if Bangladesh remains willing to construct coal plants, international financing for new coal infrastructure is becoming harder to secure.

SS Power Adds Another Large Imported-Coal Block

The private 1,320 MW SS Power plant at Banshkhali also entered commercial operation in 2023. Its first 660 MW unit began commercial production in September and its second unit followed in October.

SS Power therefore adds substantial baseload capacity. But from a national energy-security perspective, it does not remove the core vulnerability. The plant also relies on imported coal. Bangladesh has diversified ownership and plant location.

It has diversified fuel supply much less.

Barapukuria Shows Why Domestic Coal Cannot Easily Fill the Gap

Bangladesh does have domestic coal. Barapukuria proves that domestic coal can generate electricity and reduce exposure to international fuel markets.

But its scale is limited. BPDB's 2022–23 figures show just how uneven utilization can be even within the same power station.

The older Barapukuria units operated at a plant factor of about 14% and recorded a generation cost of Tk 20.59/kWh. The newer 274 MW unit operated at about 65% and generated at Tk 9.91/kWh. Together, BPDB recorded 494 MW of effective listed capacity and an average generation cost of Tk 11.51/kWh.

Meanwhile, the country's only operating coal mine was producing around 2,500–3,000 tonnes per day.

Bangladesh possesses much larger underground coal resources, but expanding extraction involves difficult questions around mining method, land acquisition, groundwater, agriculture, displacement and environmental impact.

Domestic coal therefore cannot simply be assumed to replace millions of tonnes of imported coal whenever an international supply problem occurs.

The Adani Deal Shows a Different Type of Import Risk

The Godda project in Jharkhand is different because Bangladesh imports electricity rather than physically importing the coal itself.

Under the 2017 PPA, Adani Power's plant can supply 1,496 MW net to Bangladesh for 25 years through a dedicated transmission connection. Full-load supply from both units began in 2023. Before commercial supply began, the coal-pricing mechanism became controversial.

A Power Cell assessment reported in early 2023 compared an Adani coal quotation with the prices then being paid by Bangladeshi coal plants. The reported Adani price was substantially higher, prompting BPDB to seek relief on the energy charge. Government officials said the final coal price would follow the contractual pricing mechanism and would remain competitive, while Adani later indicated that it would adjust coal costs in line with comparable plants.

The first actual BPDB data therefore matter more than the early estimates. For FY2022–23, BPDB recorded electricity from Adani at Tk 14.02/kWh.

That was significantly higher than BPDB's average cost of other Indian imports at Tk 8.77/kWh. But it was slightly below Rampal's Tk 14.12 and below Payra's Tk 16.02 during the same financial year.

So describing Adani simply as “Bangladesh's most expensive coal power” would not be supported by the available FY2022–23 evidence.The stronger concern is structural.

Bangladesh entered a 25-year cross-border commitment for almost 1.5 GW of power whose energy cost remains linked to imported coal and international prices. That adds another long-term external dependency to a system already exposed to imported coal, LNG and petroleum.

Gas Is Still the Backbone, and That Is Another Vulnerability

Coal attracts attention because many of the newest mega-projects use it. But natural gas remains much more important. Gas produced 52% of Bangladesh's electricity in FY2022–23.

Historically, domestic natural gas gave Bangladesh relatively inexpensive power. BPDB's own gas plants averaged Tk 5.13/kWh during FY2022–23, far below most oil and imported-coal generation. The problem is supply.

Domestic production is not growing fast enough to satisfy total demand. Bangladesh therefore increasingly supplements domestic gas with imported LNG.

By March 2023, imported LNG was meeting around 25% of national gas demand. High international prices after Russia's invasion of Ukraine had already forced Bangladesh to suspend spot-market purchases temporarily to conserve foreign currency.

By October, Petrobangla was supplying roughly 2,600 mmcfd against demand exceeding 4,000 mmcfd, according to officials. Budget constraints had contributed to reduced LNG imports.

This creates the same underlying problem seen with coal. Bangladesh can build more gas-fired power stations, but their energy security increasingly depends on whether the country can obtain and afford the molecules required to run them.

Cyclone Mocha Provided a Small Stress Test

May 2023 provided an unusually clear demonstration of this vulnerability. Both floating LNG facilities were moved or shut as a precaution before Cyclone Mocha. Roughly 650 mucid of LNG supply disappeared from the grid.

Electricity production dropped sharply and nationwide load shedding exceeded 2,000 MW. This was a temporary weather event.  But the mechanism is the same under a financial or geopolitical shock:

fuel infrastructure fails → fuel supply falls → gas plants cannot run → installed MW remain on paper while usable generation drops.

That is precisely the type of risk a resilient power system is supposed to diversify.

Oil and Quick Rentals Solved an Emergency but Became Expensive Legacy Capacity

Bangladesh's rental and quick-rental plants had a different purpose.

They were introduced when electricity shortages were severe and the country needed capacity quickly. Small oil-fired plants could be built much faster than large baseload projects.

As an emergency intervention, that had value. As a long-term electricity strategy, liquid fuel is difficult to justify at scale. Furnace oil still produced 20.7% of Bangladesh's electricity in FY2022–23, while diesel added another 2.6%.

BPDB's own HFO plants averaged approximately Tk 23.42/kWh. Its diesel plants averaged almost Tk 39.72/kWh. Rental purchases across different fuel and plant types averaged Tk 12.53/kWh.

The strategic objective should therefore be to retire inefficient liquid-fuel generation as cheaper and more secure capacity becomes genuinely usable.

Adding baseload capacity without retiring expensive old capacity simply increases the size and fixed cost of the system.

What Happens When the Mega-Projects Are All Available?

By January 2024, Bangladesh either had or was expecting several major projects to be available well before 2027–28.

Major source	Capacity relevant to Bangladesh	Position as understood by January 2024
Payra	1,320 MW	Operational
Rampal/Maitree	1,320 MW	Unit 1 commercial; Unit 2 had been synchronized and was expected to follow
SS Power	1,320 MW	Both units commercially operating
Matarbari Phase 1	1,200 MW	First unit entering operation; second expected in 2024
Adani Godda import	1,496 MW net	Full supply capacity available
Barapukuria	525 MW	Existing domestic-coal capacity
Rooppur Nuclear	2,400 MW	Units then expected around 2024 and 2025
Combined capacity	~9,581 MW	Large baseload/import blocks alone

Rooppur's two 1,200 MW units were expected, as of 2023 planning, to enter operation in 2024 and 2025.

The exact commissioning timetable can change. But the strategic picture does not depend on whether one project is delayed by several months.

By the second half of this decade, Bangladesh is positioned to have far more large baseload capacity than it had when the original expansion strategy began.

And the government's own 2023 master plan acknowledges the resulting reserve-capacity issue.

The Government's Own Master Plan Predicts Large Reserve Capacity

The Integrated Energy and Power Master Plan 2023 was formally published by the Power Cell in December 2023. Under its “In-Between” scenario, installed power capacity reaches about 41.4 GW by 2030.

The approximate planned mix is striking:

2030 source	Planned installed capacity	Approx. share
Gas/LNG	15.8 GW	38%
Coal	9.9 GW	24%
Oil	5.2 GW	13%
Electricity imports	4.1 GW	10%
Nuclear	2.4 GW	5%
Hydro, solar and wind	~3.2 GW	~8%
Other/new fuels	~0.9 GW	~2%
Total	~41.4 GW	100%

The same plan estimates maximum demand of roughly 27.1 GW in 2030 under this scenario. After accounting for availability and system planning assumptions, it still produces a reserve-capacity rate around 31%.

The alternative PP2041 case estimates supply of around 41.8 GW against approximately 29.3 GW maximum demand, producing an even larger reserve margin. The plan itself notes that committed projects cause the reserve-capacity rate to exceed 60% during parts of the 2020s.

That is perhaps the strongest evidence that Bangladesh's next electricity challenge is not primarily constructing more generation. It is making existing and committed capacity usable, affordable and resilient.

A Simple Stress Test Shows the Weakness

The 2030 mix also reveals how multiple sources can create the appearance of diversification while sharing the same underlying risk.

Shock	Parts of the system exposed	Likely consequence
Global coal-price spike	Payra, Rampal, Matarbari, SS Power, indirectly Adani	Higher generation/purchase cost and larger FX requirement
Dollar shortage	Imported coal, LNG, oil, imported power, foreign debt service	Fuel-payment delays and lower plant utilization
LNG disruption	Large gas fleet	Gas-fired generation falls despite available plant capacity
Domestic gas decline	Gas fleet, industry and captive power compete for supply	Greater LNG requirement or lower generation
Demand grows below forecast	Large committed fleet	Higher reserve margin and greater fixed/capacity-cost burden
Transmission constraint	Any large plant unable to evacuate full output	Generation remains stranded despite installed capacity
International coal-finance withdrawal	Future coal expansion	Higher financing difficulty and stranded-development risk

“This is not a prediction that all these events will occur together. It is a stress test.”

A resilient electricity system should remain functional when one major input fails. Bangladesh's emerging system instead contains several technologies whose failures can originate from the same source: foreign currency and imported fuel.

Bangladesh Has Already Seen the Warning Signs

None of these risks is theoretical. Payra lost all 1,320 MW because coal bills could not be paid. Rampal repeatedly stopped, including because of coal shortages.

Bangladesh reduced LNG purchases when international prices and foreign-exchange pressure became too high. Cyclone Mocha temporarily disrupted LNG infrastructure and immediately removed large amounts of power generation.

At the same time, BPDB's average electricity cost increased sharply while the country maintained generation capacity far above maximum output. Individually, each event can be explained. Together, they describe the structure of the system.

The Power Strategy Does Not Need More Megawatts as Its First Priority

Bangladesh deserves credit for solving a problem that once constrained homes, factories and economic growth: chronic shortage of installed generation capacity.

But infrastructure policy has to change when the bottleneck changes. The next stage should focus much less on announcing generating capacity and much more on firm energy availability.

That means better demand forecasting, stronger transmission networks, faster domestic gas exploration, competitive procurement, gradual retirement of inefficient oil plants, diversified fuel contracts, reduced exposure to capacity payments and much greater development of renewable electricity where economically viable.

Renewables alone cannot instantly replace Bangladesh's baseload fleet. Gas will remain important. Coal projects that are already completed will remain part of the grid. Nuclear power can provide another major source of baseload generation.

The objective should therefore be risk diversification, rather than replacing dependence on one fuel with dependence on another.

More Power Plants Do Not Automatically Create Energy Security

Bangladesh's power expansion has produced an impressive number of pdocution capacity. That achievement should not be confused with a secure electricity system.

A power plant is useful only when the grid can evacuate its electricity, the buyer can afford its tariff and the country can continuously obtain the fuel required to run it.

By January 2024, Bangladesh already had enough evidence to question whether generation-focused planning had moved too far ahead of these other requirements. The fundamental risk is no longer simply that Bangladesh will run out of power plants.

It is that the country could own tens of thousands of megawatts of generation capacity while still facing shortages whenever fuel, foreign exchange or infrastructure becomes constrained.

If that happens, Bangladesh will have solved the megawatt shortage without solving the electricity problem. And that would make the country's power-sector expansion far less successful than the capacity numbers suggest.