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 18,000 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 is misleading. The dispatchable subset of the fleet is substantially smaller. Roughly 3.84 GW of coal capacity built to anchor baseload is delivering, on a generous reading, around 1,600 MW in aggregate: Payra (1,320 MW nameplate) shut down on coal-supply failure, Matarbari (1,200 MW design) dispatching 315 MW in April 2026, and Rampal (1,320 MW) running near capacity. 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 (1,200 kWh), Vietnam (2,800 kWh), and the global average (3,500 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.

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 meeting 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. 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

Solar has reached 1,451 MW of installed capacity by May 2026, equal to 5.01 percent of the grid-connected fleet, of which 1,073.5 MW are grid-connected and 377.17 MW are off-grid. Total renewables including small hydro and wind stand at 1,559 MW, or 5.4% of installed capacity. 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 1,559 MW 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 is widening every year that passes at the lower rate. (Source: SREDA; PV Magazine)

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. In the spring of 2026, on the marginal kilowatt, the coal fleet's 3.84 GW of nameplate capacity is delivering roughly 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 BPDB FY2025 accounts confirm the depth of the fiscal crisis. Revenue stood at Tk 693.8 billion against expenditure of Tk 1.21 trillion. The government injected Tk 386.0 billion in subsidies; BPDB still posted a Tk 170.2 billion net loss. Capacity charges alone consumed Tk 420 billion, equal to 60 percent of total electricity sales revenue, paid to plants substantially not dispatching. Power sector accumulated debt exceeds BDT 1000 billion. (Source: Read On Substack)

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 owes approximately USD 850 million for Jharkhand-imported electricity. The Tarique Rahman government, sworn in February 17, 2026, launched a power-deal renegotiation within weeks of inauguration. The 180-day priority plan identifies uninterrupted electricity and gas supply as one of four national priorities. Government communications have framed estimated FY26 savings from the renegotiation at approximately Tk 14,000 crore (Tk 140 billion). The renegotiation track is necessary and overdue; the Tk 420 billion capacity-charge bill is approximately one percent of GDP, paid largely to plants not dispatching. Cutting it by Tk 140 billion is a meaningful one-third reduction. (Source: BDNews24; IEEFA)

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: BDNews24; IEEFA)

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; BDPolicy Lab energy.py)

1. Resolve the coal fleet now. Either subsidise coal supply to bring Payra back online and Matarbari to design output, or formally retire the plants and write off the financial liability through bondholders and the lender club. The current limbo is the worst option: capacity charges accrue while kilowatt-hours do not.
2. Set the solar procurement cadence. A standardised PPA template, a calendar of quarterly tender rounds through 2030, a dedicated grid-evacuation capital programme synchronised to the renewable build, and statutory land-allocation timelines. The 523 MW PPA signed in January 2026 shows the supply side responds when the demand is structured. Triple the annual deployment rate from 0.5 GW to 1.5 GW or the 2030 target becomes unreachable.
3. Tariff reform with targeted protection. Move to cost-reflective pricing for commercial and industrial users while maintaining means-tested lifeline tariffs for households below the poverty line. Use the fiscal space created to retire BPDB debt and fund renewable investment. Phase out regressive blanket subsidies that benefit affluent urban consumers.
4. IPP contract rationalisation on dispatch basis. Capacity payments tied to dispatched megawatt-hours, not nameplate availability. Sunset clauses on contracts entered under the 2010-2015 quick-rental regime. The FY26 Tk 14,000 crore renegotiation saving is a floor, not a ceiling.
5. Manage LNG foreign-exchange exposure structurally. Expand the India-Bangladesh interconnection from 1160 MW to 3,000-5,000 MW. Develop trilateral Nepal-India-Bangladesh hydropower arrangements. Lock in long-term LNG contracts at fixed pricing rather than spot-market dependency. Transparent parliamentary reporting on the contracted LNG cost line in the budget.