The State of Bangladesh Energy

Executive Summary

Bangladesh faces a structural energy crisis with a hard deadline: domestic gas reserves of 8.5 TCF are projected to deplete by approximately 2031, yet renewables supply only 5.4% of installed generation capacity against a government target of 30% by 2041. The gap is 24.6 percentage points and is not closing fast enough. Power sector debt has surpassed BDT 1000 billion, driven by BDT 386 billion in annual subsidies and idle IPP capacity payments on a 28.9 GW fleet that cannot run at full load because domestic gas supply (2900 MMCFD) is declining sharply while demand stands near 18.2 GW. LNG imports (1100 MMCFD, 27.5% of total gas supply) cost roughly three times the administered domestic gas price, compounding fiscal pressure with every additional cargo. Three decisions taken in the next 24 months, on tariff reform, renewable auction scale, and regional power trade, will determine whether Bangladesh averts a supply crisis before 2031 or enters a decade of expensive emergency LNG dependence.

The Gas Clock Is Running

Domestic gas production at 2900 MMCFD is declining sharply (period change: -16.4%). All major producing fields, Bibiyana, Titas, Habiganj, Rashidpur, and Kailashtila, are on mature decline curves. Proven reserves of 8.5 TCF provide a production runway to approximately 2031 at current extraction rates. No commercial offshore discovery has emerged from successive Production Sharing Contract licensing rounds, and the geological uncertainty of the deep-water Bengal Fan makes a material near-term find unlikely. The depletion trajectory is effectively locked in.

Gas accounts for 52% of Bangladesh's primary energy mix. Unlike economies that have always imported energy at world market prices, Bangladesh built its industrial base on cheap domestic gas at BDT 2.75 per cubic metre. The transition to imported LNG at $10-14 per MMBTU is a structural cost shock, not a cycle, and it is already reshaping unit economics across fertiliser, ceramics, textiles, and power generation.

Base case: Production decline continues at the current pace; LNG dependency rises from 27.5% toward 50%+ by 2028 as a third FSRU comes online. Total gas import cost grows proportionally, widening the BPDB revenue gap unless tariffs adjust.

Risk case: A global LNG supply shock (comparable to 2022) pushes spot LNG above $30/MMBTU during a Bangladesh summer peak. With insufficient storage and no price hedge, load-shedding on the scale of 2022-23 returns, costing an estimated 1-2% of GDP in manufacturing output loss.

Power Sector: Capacity Overstated, Margins Thin

Installed capacity of 28.9 GW looks comfortable against peak demand of 18.2 GW and a nominal reserve margin of 58.5%. That margin is misleading. Derated capacity, accounting for aging plants, forced outages, and gas supply constraints, reduces dispatchable generation significantly below nameplate. Summer peak effective margins are thinner, and load-shedding in industrial zones and rural distribution networks remains a recurring outcome.

IPPs account for 48.0% of installed capacity, enabling rapid capacity additions but creating a structural cost problem: BPDB pays capacity charges regardless of whether plants dispatch. Gas-constrained IPPs sitting idle while BPDB absorbs their fixed-cost obligations represent a deadweight fiscal transfer that compounds the subsidy burden. System T&D losses at 8.0% have improved from 15-16% a decade ago, but still mean roughly one unit in every twelve generated is lost before reaching a consumer. Reducing losses to the 6-7% range of better-performing regional peers would add over 1,000 MW of effective capacity at no capital cost.

Total generation of 101.7 billion kWh is growing, but efficiency of the overall system, measured by fuel cost per kWh delivered, is deteriorating as the gas-to-LNG shift continues.

Renewable Gap: The Most Consequential Implementation Failure

At 5.4% of installed generation capacity, Bangladesh's renewable share is 24.6 percentage points below the SREDA 2041 target of 30%. Peer economies are demonstrably further ahead: India deployed 200 GW of renewables by 2024, Vietnam scaled solar from near-zero to 20 GW in five years, and the Philippines is tracking toward 35% renewable share by 2030. Bangladesh's programme, by contrast, has stalled at grid scale despite the IDCOL Solar Home Systems programme deploying 6.5 million units and demonstrating consumer acceptance of solar at pace.

Three bottlenecks explain the stall. Land scarcity in the world's most densely populated major economy forecloses large utility-scale ground-mount projects. Grid architecture designed for centralised gas-fired dispatch cannot absorb variable renewable generation without investment in storage and smart grid controls. And PPA terms and net-metering policy have been insufficiently attractive to mobilise private capital at the required scale. These are solvable problems: floating solar on rivers and water bodies, canal-top installations, and 3.5 GW of estimated urban rooftop potential all reduce land competition. India's auction programme drove solar tariffs below $0.03/kWh in comparable irradiance conditions (4-5 kWh/m2/day).

The Rooppur Nuclear Power Plant (2.4 GW), at approximately $12.6 billion the largest single energy investment in Bangladesh's history, provides baseload emissions-free capacity when commissioned. Unit 1 commissioning is targeted for 2025-2026. The strategic logic is sound: baseload nuclear displaces expensive LNG and provides dispatchable power that variable renewables cannot. The dependency risks are real: Russian TVEL fuel supply chains, sovereign debt obligations denominated in US dollars, operational workforce readiness in a flood-prone geography, and the absence of a domestic nuclear fuel cycle. On balance, Rooppur is the right call given Bangladesh's baseload gap, but it is insufficient on its own.

Coal-fired capacity of 3840 MW (Payra, Rampal, and Matarbari phases) faces stranded-asset risk as global capital markets exit coal financing. Matarbari, funded by JICA, is almost certainly Bangladesh's last internationally financeable coal project. Every gigawatt locked into coal is a gigawatt not building the renewable base.

Import Exposure and the Balance-of-Payments Constraint

WTI crude at $99.89/barrel, with the energy commodity index at 242.28 (risen 52.2% year-on-year), keeps Bangladesh's petroleum import bill near $7.0 billion annually. This is one of the largest single foreign exchange drains in the merchandise account. Every $10/barrel increase in crude prices adds an estimated $700-900 million to the annualised import bill, a direct transmission channel to foreign reserve pressure that Bangladesh cannot hedge without financial instruments it has not deployed.

The LNG cost trajectory is structurally worse. At 27.5% of total gas supply and climbing, and at a price roughly three times the administered domestic rate, the annual LNG import cost is already embedded in BPDB's widening losses. The cross-border import from India at 1160 MW offers a partial offset: Indian electricity, particularly hydropower and cheaper coal, arrives at prices consistently below LNG-fired generation. Expanding interconnection capacity to 3,000-5,000 MW is the fastest, lowest-capital-cost route to reducing LNG exposure.

Energy Poverty: Access Without Adequacy

Bangladesh achieved 99.5% electrification by March 2022, a genuine policy success. But electrification is not adequacy. Per-capita electricity consumption of 560 kWh places Bangladesh at roughly one-fifth the global average (~3,500 kWh), below India (~1,200 kWh), and far below Vietnam (~2,800 kWh). Energy use per capita at 287.8 kg of oil equivalent confirms systemic energy poverty that caps industrial productivity and household welfare. Bangladesh cannot reach upper-middle-income status at 560 kWh; Vietnam's manufacturing acceleration tracked closely with its shift past 2,000 kWh per capita.

Clean cooking coverage at 28.0% means 72% of households still rely on biomass (wood, cow dung, crop residues). WHO estimates attribute approximately 78,000 premature deaths annually to indoor air pollution in Bangladesh, concentrated among women and children. Biomass dependence also drives deforestation and absorbs household labour hours that would otherwise contribute to economic output. LPG distribution logistics and cylinder affordability are the binding constraints; a targeted lifeline LPG subsidy for the lowest two income quintiles, replacing the current blanket energy subsidy, would be more cost-effective and progressive.

CO2 emissions per capita at 0.52 metric tons are among the lowest globally, reflecting energy poverty rather than efficiency. Emissions will rise as development proceeds. The policy question is whether that growth is powered by domestic renewables or expensive imported fossil fuels.

Financial Sustainability: The Fiscal Trap

Power sector debt exceeding BDT 1000 billion, driven by BDT 386 billion in annual energy subsidies, is structurally unsustainable. The subsidy regime is also regressive: affluent urban households consuming 300+ kWh per month capture more absolute subsidy value than rural households on lifeline tariffs. Without tariff reform, BPDB cannot fund grid modernisation, renewable integration infrastructure, or debt service, perpetuating the fossil dependency that generates the losses in the first place.

This is a fiscal trap with a clear exit path. Cost-reflective pricing for commercial and industrial consumers would generate sufficient revenue to service BPDB debt, fund renewable procurement, and maintain targeted lifeline tariffs for low-income households. The political economy is difficult but the arithmetic is not: the subsidy bill at BDT 386 billion per year, compounding as LNG volumes rise, grows faster than any realistic tariff adjustment trajectory.

Three Priority Actions

1. Launch a 5 GW renewable auction in 2025. Issue standardised, transparent competitive tenders for solar capacity (floating, rooftop, and ground-mount), modelled on India's programme that drove costs below $0.03/kWh. Pair procurement with battery storage co-location requirements and grid code reform to enable variable renewable dispatch. Five gigawatts at India-comparable tariffs would cost less per unit of output than continued LNG procurement at current prices.

2. Reform tariffs before the LNG bill doubles. Implement cost-reflective pricing for commercial and industrial consumers in a phased schedule over 24 months. Ring-fence the fiscal space to retire BPDB debt and capitalise a renewable infrastructure fund. Protect low-income households through means-tested lifeline tariffs. Delaying this reform raises the eventual adjustment cost and increases the probability of a disorderly fiscal event in the power sector.

3. Expand cross-border power trade to 3,000 MW by 2030. Accelerate the India interconnection from 1160 MW and negotiate trilateral Nepal-India-Bangladesh hydro transit arrangements. Regional clean power, including Nepali run-of-river hydro, arrives dispatchable at competitive prices relative to LNG-fired generation, reduces foreign exchange outflows, and does not require domestic land acquisition or local permitting.

Data sources: EIA, World Bank Development Indicators, FRED (Federal Reserve Bank of St. Louis), Petrobangla Annual Reports, BPDB Annual Reports, SREDA, IDCOL, IRENA Renewable Capacity Statistics, Bangladesh Bureau of Statistics.