The State of Bangladesh Energy

Chapter 1

Power System: Capacity, Demand, and the Adequacy Gap

Bangladesh's grid-connected generation fleet stands at 28.9 GW as of May 2026, rising to approximately 32.3 GW when captive industrial generation is included. Summer 2026 peak demand is forecast at 18,250 MW (range 18,000 to 18,500 MW), growing roughly seven percent annually, with the projection that peak crosses 25,000 MW by 2030. The installed base was built in a fifteen-year expansion programme beginning in 2009, enabling Bangladesh to achieve 100 percent electrification by March 2022. The electrification rate stands at 99.5% of households, driven by grid extension through the Rural Electrification Board and IDCOL's off-grid solar home system programme.

The headline installed figure overstates usable supply. The dispatchable subset of the fleet is substantially smaller. The 3.84 GW of coal capacity built to anchor baseload is running well below nameplate: Payra (1,320 MW) shut on coal-supply failure, Matarbari (1,200 MW design) dispatching 315 MW in April 2026, and Rampal (1,320 MW) running near capacity. With Payra at zero and Matarbari at 315 MW, observed coal dispatch in spring 2026 is on the order of 1,600 MW against 3.84 GW of nameplate. The 2010-2015 quick-rental boom added several gigawatts of oil and furnace-oil IPPs that run only at extreme peak; the rest of the year they collect capacity charges without delivering electrons. Gas-fired plants carry the bulk of baseload dispatch, and the gas supply constraint is the binding limit on the whole system. (Source: Dhaka Tribune; GEM Wiki)

System Loss and Consumption Gap

Transmission and distribution losses stand at 8.0%, improved from 15-16 percent a decade ago but still meaning roughly one unit in twelve generated never reaches a paying consumer. Reducing losses to the 6-7 percent range achieved by better-performing regional utilities would be equivalent to adding over 1,000 MW of effective capacity without building a single new plant.

Per-capita electricity consumption at 560 kWh remains far behind India (1,460 kWh in FY2024-25) and Vietnam (about 3,000 kWh in 2024), and is roughly one-sixth of the global average of about 3,600 kWh. Total generation of 101.7 billion kWh serves a population of 174 million, but 100 percent access has not translated into adequate supply. Industrial consumers face scheduled and unscheduled outages that reduce productivity, raise diesel-generator costs, and deter energy-intensive manufacturing investment. (Source: India Ministry of Power 2025; World Bank WDI; Our World in Data)

Chapter 2

Gas Crisis: Depleting Reserves and the LNG Dependency Trap

Natural gas at 52% of primary energy supply has powered Bangladesh's development model for four decades. The structural crisis is this: domestic production at approximately 2900 MMCFD is already short against a system demand exceeding 4,000 MMCFD, a 27 percent structural shortfall. Petrobangla's latest published reserves figure is 8.50 TCF remaining recoverable as of June 2023, against historical extraction of approximately 20.33 TCF from a discovered base of 28.79 TCF. At current extraction rates, production will decline to marginal levels by approximately 2031. (Source: Gas Outlook; Petrobangla)

The major producing fields (Bibiyana, Titas, Habiganj, Rashidpur, Kailashtila) are all on mature decline curves. Bibiyana alone accounts for nearly 40 percent of total output and has entered plateau production. Exploration in the Bay of Bengal continental shelf has yielded no commercial discoveries despite multiple Production Sharing Contract rounds. The 2024 offshore-block auction may produce commercial discoveries on a decade-plus horizon; it does nothing for the second-half-of-the-2020s shortfall.

LNG Doubling and the Foreign-Exchange Commitment

Petrobangla has contracted to roughly double LNG imports from 3.5 to 7.5 million tonnes per year starting in early 2026 under newly signed agreements. Re-gasification capacity is climbing from 1.0 to approximately 2.20 billion cubic feet per day by year-end 2026, with a land-based terminal planned for the 2031-32 horizon. Imported LNG already supplies 27.5 percent of total gas supply. The substitution from domestic gas to imported LNG is a real engineering programme; it is also a permanent foreign-exchange commitment denominated in dollars and indexed to oil. At current Brent-linked contract pricing, 7.5 Mtpa of LNG costs approximately USD 5-6 billion annually. (Source: Inspira-BD)

The cost differential is the core problem: imported LNG at $10-14 per MMBTU costs approximately three to five times the administered domestic gas price of $2.75 per MMBTU. Every additional molecule of LNG that replaces depleting domestic gas widens the gap between the cost of supply and regulated tariffs that Petrobangla and BPDB must absorb as losses. With WTI crude at $100/barrel, the petroleum and LNG import bill already stands at approximately $7.0 billion annually, one of the largest single contributors to the merchandise trade deficit.

Pricing Reform Imperative

The dual-price system, where domestic gas is sold at $2.75/MMBTU while imported LNG costs $10-14/MMBTU, creates perverse incentives. Industrial consumers have no price signal to conserve or switch fuels. Fertiliser plants receive gas at subsidised rates that make domestic production appear cheaper than import alternatives, but the subsidy cost is borne by the energy system rather than the agriculture budget, obscuring true fiscal exposure. Gradual gas price reform moving toward blended cost-of-supply pricing is essential but politically difficult in an economy where gas-intensive industries employ millions.

Chapter 3

Renewable Transition: Deployment Starting to Register, Target Still Out of Reach

Installed renewable capacity stands at roughly 1.69 GW, equal to about 5.4 percent of total installed generation capacity, of which about 1.40 GW is grid-connected; the balance is off-grid solar. The Renewable Energy Policy 2025 targets 20 percent of installed capacity from renewables by 2030 (approximately 6,145 MW) and 30 percent by 2041 (approximately 17,470 MW). To reach 6,145 MW from about 1.69 GW today, the country needs to add roughly 1.1 GW of renewable capacity annually for the next four-and-a-half years. The current pace is closer to 0.5 GW annually. The gap widens every year that passes at the lower rate. (Source: SANEM Energy Outlook Vol.2 Iss.4, April 2026, citing SREDA dashboards)

The recent tender pipeline shows the supply side responds when demand is structured. The Bangladesh Power Development Board floated a 2.65 GW utility-scale solar tender in March 2025; 523 MW of PPAs were signed in January 2026; a further 77.6 MW of tenders were launched in April 2026. The tender-cleared prices in the March 2025 round came in below the variable cost of coal or LNG-fired generation at international prices. The constraint is not economics or technology; it is the absence of a quarterly tender cadence, a standardised PPA template, and a synchronised grid-evacuation capital programme.

Solar: Off-Grid Success, Grid-Scale Stall

The IDCOL Solar Home Systems programme deployed over 6.5 million units across rural Bangladesh, the world's largest off-grid solar programme. Yet the transition to grid-scale renewable generation has stalled at structural rather than technical barriers. Land scarcity in the world's most densely populated major country limits utility-scale farms. Grid infrastructure designed for centralised gas-fired generation cannot easily absorb intermittent renewable output without transmission upgrades. Floating solar on Bangladesh's extensive water bodies (haors, rivers, coastal ponds) represents an underexplored pathway that could bypass the land constraint. The Vietnam comparison from 2017-2020, when that country added more than 16 GW of solar in three years via a standardised feed-in tariff, is the benchmark Bangladesh's policy machinery has not yet been willing to copy.

Rooppur Nuclear: Baseload Bet

The Rooppur Nuclear Power Plant (2.4 GW), Bangladesh's largest single energy investment at approximately $12.6 billion, is intended to provide emissions-free baseload power. Unit 1 commissioning is expected in 2025-2026, with Unit 2 following 12-18 months later. The strategic logic is sound: firm, dispatchable capacity that complements intermittent renewables and reduces gas dependency. However, the project introduces long-term dependency on Russian fuel supply chains (TVEL Corporation), carries sovereign debt obligations for the $11.38 billion Russian credit line extending over two decades, and requires world-class regulatory capacity in a flood-prone, seismically active geography.

Coal: Functionally Stranded

The 3.84 GW coal fleet (Payra 1,320 MW, Rampal 1,320 MW, Matarbari 1,200 MW) was conceived when coal appeared to be the cheapest pathway to baseload expansion. The Finance Ministry has suspended subsidy disbursements to Rampal and Payra since May 2025; the arithmetic of importing coal at international prices, with no subsidy to bridge the gap to the contracted tariff, does not clear. Payra is shut; Matarbari runs at one-quarter of design; Rampal continues to run. With Payra at zero and Matarbari at 315 MW in April 2026, observed dispatch from the 3.84 GW coal fleet is on the order of 1,600 MW. Japan's JICA-funded Matarbari is likely the last major coal project Bangladesh will finance internationally; global capital markets are exiting coal, and the EU Carbon Border Adjustment Mechanism will penalise carbon-intensive exports. (Source: Dhaka Tribune; GEM Wiki)

Chapter 4

Financial Sustainability: Debt, Subsidies, and the IPP Burden

The depth of the fiscal crisis is in the FY2024-25 numbers. BPDB's aggregate revenue shortfall reached Tk 556.6 billion (USD 4.55 billion), an 18.3 percent year-on-year increase, driven by a loss of about Tk 5 per kilowatt-hour as generation cost outran the regulated tariff. The government covered the bulk of it, injecting Tk 386 billion (USD 3.16 billion) in subsidies. The structural cause is overcapacity: with installed capacity running 58 percent above peak demand (IEEFA puts the margin above 60 percent), BPDB is obliged to pay capacity charges to almost all non-renewable plants whether or not they dispatch. Accumulated sector debt exceeds BDT 1000 billion. (Source: IEEFA 2026)

The subsidy structure is regressive: affluent urban households consuming 300-plus kWh per month benefit more in absolute terms than rural households on lifeline tariffs consuming 50-100 kWh per month. The political economy of tariff reform has trapped successive governments into under-pricing electricity, accumulating BPDB losses, and periodically seeking finance ministry bailouts.

The IPP Capacity Payment Problem

IPPs account for 48.0% of installed capacity. The model enabled rapid capacity addition during the 2009-2018 build-out, but created a structural liability: BPDB must pay capacity charges regardless of dispatch. With many gas-fired IPPs unable to run at full load due to gas supply constraints, BPDB pays idle capacity charges that are a deadweight fiscal cost for generation capacity that produces no electricity. The concentration of contracts in oil-fired and furnace-oil plants originally intended as short-term rental capacity has persisted far beyond planned timelines.

Adani Power and the Tarique Renegotiation

Under the Adani Power contract, Bangladesh has faced sizeable disputed dues; as of late 2025, BPDB had cleared a tranche against Adani's claim of approximately USD 495 million. The Tarique Rahman government, sworn in February 17, 2026, launched a power-deal renegotiation within weeks of inauguration, seeking lower rates after a national review committee found the deal had cost an extra USD 400-500 million annually. The 180-day priority plan identifies uninterrupted electricity and gas supply as one of four national priorities. The renegotiation track is necessary and overdue, but it reduces cost on existing contracts rather than adding supply. (Source: CPD IRBD FY26; Bloomberg; BDNews24)

The renegotiation does not, however, address the substitution question on the supply side. Reducing capacity payments saves fiscal cost on the existing fleet. It does not by itself replace the gigawatts of dispatch the country will need in 2028 and beyond as gas depletes and demand grows.

Chapter 5

Energy Security Strategy: What the BNP Government Must Decide in the Next Six Months

The Tarique Rahman government has bought time on the cost side through the IPP renegotiation and the Adani repricing. It has not yet bought time on the supply-substitution side. The 180-day plan reads as cost-recovery on the existing system, not as substitution to the next system. Five decisions in the next six months determine the trajectory for the rest of the decade. (Source: IEEFA 2026; BDNews24)

Cross-Border Electricity Trade

Cross-border electricity imports from India currently provide 1160 MW through several interconnection points. This capacity could expand to 3,000-5,000 MW through additional high-voltage DC links and substation upgrades. Trilateral arrangements to import Nepali hydropower through Indian transmission corridors would provide access to clean, dispatchable power at prices competitive with LNG-fired generation. The Adani renegotiation should not slow the broader cross-border integration agenda with Nepal, Bhutan, and the eastern Indian states whose seasonal hydroelectric surplus matches Bangladesh's seasonal demand peak.

Clean Cooking Transition

Clean cooking coverage at 28.0% (LPG or improved cookstoves) means roughly 72 percent of households still rely on biomass, including wood, cow dung, and crop residues. Indoor air pollution from traditional cookstoves causes an estimated 78,000 premature deaths annually (WHO), disproportionately affecting women and children. Biomass collection consumes hours of daily labour, primarily by women and girls, reducing time available for education and economic activity. Electric cooking on induction stoves is an emerging pathway that could leverage grid electrification, but requires reliable supply and affordable tariffs.

Energy Storage and Grid Modernisation

Battery energy storage systems are absent from Bangladesh's current energy mix, a critical gap for any serious renewable integration strategy. Grid frequency regulation, peak shaving, and renewable intermittency management all require storage capacity that does not exist. Declining lithium-ion battery costs (now below $140/kWh for utility-scale systems) make storage economically viable, but Bangladesh has no procurement framework, no grid code provisions, and no incentive structure for storage deployment. The transmission system needs smart grid technologies and upgraded substations to handle bidirectional power flows from distributed solar generation.

Policy Priorities

Five Decisions That Determine the Energy Decade

The five-year window from May 2026 to mid-2031 is the interval in which the substitution choice is made by decision or by default. CO2 emissions per capita at 0.52 metric tons reflect energy poverty rather than efficiency; emissions will rise as development proceeds. The question is whether growth is powered by expensive imported fossil fuels or domestically sourced renewables. (Source: IEEFA 2026; BDPolicyLab energy.py)

1. Resolve the coal fleet now. Owner: Power Division with the Finance Ministry. Either restore coal supply to bring Payra back online and Matarbari to design output, or formally retire the plants and write off the liability with the lender club. Success signal: zero capacity charges paid to a non-dispatching coal plant for two consecutive quarters by mid-2027. The current limbo is the worst option, accruing charges while kilowatt-hours do not.
2. Set the solar procurement cadence. Owner: SREDA and BPDB. A standardised PPA template, a published calendar of quarterly tender rounds through 2030, a dedicated grid-evacuation capital programme, and statutory land-allocation timelines. The 523 MW PPA signed in January 2026 shows the supply side responds when demand is structured. Success signal: the annual renewable build rate roughly doubles from about 0.5 GW to 1.0-1.1 GW by FY2028, the minimum trajectory to reach 6,145 MW by 2030.
3. Tariff reform with targeted protection. Owner: BERC and the Finance Ministry. Move to cost-reflective pricing for commercial and industrial users while maintaining means-tested lifeline tariffs for households below the poverty line. Success signal: BPDB's per-unit loss of about Tk 5/kWh narrows by at least half within two fiscal years, with the subsidy bill falling below Tk 300 billion. Phase out blanket subsidies that benefit affluent urban consumers.
4. IPP contract rationalisation on dispatch basis. Owner: BPDB. Tie capacity payments to dispatched megawatt-hours, not nameplate availability, and apply sunset clauses to contracts entered under the 2010-2015 quick-rental regime. Success signal: a measurable year-on-year fall in capacity payments to plants running below a defined minimum capacity factor.
5. Manage LNG foreign-exchange exposure structurally. Owner: Power Division and Petrobangla. Expand the India-Bangladesh interconnection from 1160 MW toward 3,000-5,000 MW, develop trilateral Nepal-India-Bangladesh hydropower arrangements, and lock in long-term LNG contracts at fixed pricing rather than spot-market dependency. Success signal: transparent parliamentary reporting on the contracted LNG cost line in every budget, and a declining spot share of total LNG procurement.

The Counterargument, and What Would Change the Call

The strongest case against accelerating the renewable build is grid stability: a system designed for centralised gas-fired dispatch absorbs intermittent solar poorly without storage and transmission upgrades that Bangladesh has not financed, and land scarcity is real. That case holds only if storage and grid investment lag the solar build. It collapses if the grid-evacuation and storage programmes are sequenced ahead of generation tenders, which is precisely the cadence the policy priorities above demand. The conclusion would change if domestic gas exploration delivered a major commercial discovery this decade, or if cross-border hydro imports scaled faster and cheaper than utility-scale solar. Neither is in evidence today.