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Narrative 2026-05-16

Five Years from the Gas Cliff

Domestic gas reserves are estimated to deplete by 2031. LNG already covers a quarter of supply at international prices. Solar is the only path that scales fast enough.

Five Years from the Gas Cliff

Executive Summary. Bangladesh's domestic gas reserves are on track to fall below 2,000 MMCFD by 2031, yet the system already faces a 27 percent supply shortfall at 2,900 MMCFD against 4,000 MMCFD demand. The 3.84 GW coal fleet built over 2017-2024 is functionally stranded: Payra (1,320 MW) shut from coal-supply failure, Matarbari dispatching 315 MW against a 1,200 MW design, Rampal alone running near capacity. The LNG doubling from 3.5 to 7.5 Mtpa fills the near-term gap at dollar-indexed cost. Solar is the only substitution path that scales fast enough to meet the 2030 target of 6,145 MW renewables, but the current deployment rate of roughly 0.5 GW per year needs to at least triple. The five-year window to make this choice by decision, rather than by default, opens now.

In the control room of the Matarbari Ultra-Supercritical Coal-Fired Power Plant on an April morning in 2026, three weeks after the plant formally began full-scale generation, the duty engineer was watching his generation desk dispatch 315 megawatts out of a design nameplate of 1,200. The constraint was not turbine, not steam cycle, not transmission. The constraint was coal. The 1,320-megawatt Payra coal plant down the Bay of Bengal coast had been shut down on its own coal-supply failure earlier in the year, and Matarbari, sharing the same import-coal logistics chain and the same Finance Ministry subsidy regime, was operating in the same fuel shortage. Since May 2025 the Finance Ministry has suspended subsidy disbursements to Rampal and Payra. The arithmetic of importing coal at international prices, with no subsidy to bridge the gap to the contracted tariff, does not clear. Rampal continues to run; Payra does not; Matarbari runs at a quarter of design. The country built 3.84 gigawatts of coal capacity over 2017 to 2024. In the spring of 2026, on the marginal kilowatt, that capacity functionally is not there.

Two hundred kilometres west, on the same week, a spinning mill in Tongi was running its captive gas-fired generator at eight megawatts against a rated twelve. The grid-supplied gas pressure at the meter was nine PSI against a rated fifteen. The constraint there was not the generator either. It was that domestic gas production at approximately 2,900 million cubic feet per day is now meeting against a system demand that exceeds 4,000 MMCFD, and the gap is being closed by LNG imports whose pricing is set in Brent-linked international markets and whose throughput is constrained by a re-gasification capacity that is in the middle of being doubled but is not doubled yet. When LNG cargoes are timely, the gap narrows; when a cargo is delayed by even days, the pressure at the Tongi meter drops.

The country imported its way out of the immediate 2024 reserves crisis. It is now importing its way into a permanent fuel-import dependency that the next five years will deepen unless the substitution decision is made now.

What was built and what is operating

Bangladesh's installed generation capacity as of May 2026 stands at approximately 28,919 megawatts on the grid-connected fleet, rising to about 32,332 megawatts when captive industrial generation is included. Summer 2026 peak demand is forecast at 18,000 to 18,500 megawatts, growing roughly seven percent annually with the projection that peak crosses 25,000 megawatts by 2030. On the surface, headroom of nine to ten gigawatts looks comfortable.

The headroom is illusory because the dispatchable subset of the fleet is much smaller than the installed number. Roughly 3.84 gigawatts of coal sits in three plants that should anchor the baseload (Payra 1,320, Rampal 1,320, Matarbari 1,200) and is currently delivering, on a generous reading, perhaps 1,600 megawatts on aggregate. The 2010 to 2015 quick-rental boom built several gigawatts of oil and furnace-oil capacity that is uneconomic to dispatch at current fuel prices and that runs only at extreme peak; the rest of the year, these plants collect capacity charges without delivering electrons. In FY25 the Bangladesh Power Development Board paid Tk 420 billion in capacity charges alone, up Tk 100 billion year-on-year, against total electricity sales revenue of Tk 693.8 billion. The capacity-charge bill is sixty percent of revenue. After the government injected a record Tk 386.4 billion in subsidies, BPDB still posted a Tk 170.2 billion loss for the fiscal year.

Gas-fired plants carry the bulk of baseload dispatch. The supply side of that arithmetic is the binding constraint. Petrobangla's latest published reserves figure is approximately 8.46 trillion cubic feet remaining recoverable as of June 2023, against historical extraction of approximately 20.33 TCF from a discovered base of 28.79 TCF. Domestic gas production is around 2,900 MMCFD; system demand exceeds 4,000 MMCFD, a structural shortfall of roughly 27 percent that has to be filled from elsewhere. 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.

The closing-the-gap path the country has taken is imported LNG. Petrobangla contracts will 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. A land-based LNG terminal is planned for the 2031-32 horizon. A new USD 1.4 billion gas pipeline is under development. The substitution from domestic gas to imported LNG is a real engineering programme; it is also a permanent foreign-exchange commitment denominated in dollars at oil-linked prices.

The renewable build that is starting to register

The renewable share of installed capacity has moved meaningfully off the 2021 floor. Solar reached 1,451 megawatts of installed capacity by May 2026, equal to roughly five percent of the installed fleet, of which 1,073.5 megawatts are grid-connected and 377.17 megawatts are off-grid. Total renewables including small hydro and wind stand at 1,559 megawatts. The Renewable Energy Policy 2025, in draft form, targets twenty percent of installed capacity from renewables by 2030 (approximately 6,145 megawatts) and thirty percent by 2041 (approximately 17,470 megawatts). The Bangladesh Power Development Board floated a 2.65-gigawatt utility-scale solar tender in March 2025; 523 megawatts of PPAs were signed in January 2026; a further 77.6 megawatts of tenders were launched in April 2026.

The deployment pace is the part that matters. To reach 6,145 megawatts of renewable capacity by 2030 from approximately 1,559 megawatts today, the country needs to add roughly 1.1 gigawatts of renewable capacity annually for the next four-and-a-half years. The current pace, judged by the 523-megawatt PPA signing and the new 77.6-megawatt tender, is closer to half a gigawatt annually. The gap is widening every year that passes at the lower rate.

The constraints have been studied repeatedly: grid evacuation capacity at the points where solar resource is best (the southern coastal belt, Greater Faridpur, the western drought-prone districts) is insufficient and is not being expanded fast enough by the Power Grid Company; the land-acquisition pipeline runs through five agencies in series rather than in parallel; the power-purchase agreement template has been negotiated rather than standardised, with bespoke dispatch, curtailment, and currency-conversion terms in every project. The Vietnam comparison from 2017 to 2020, when that country added more than 16 gigawatts of solar in three years via a standardised feed-in tariff with statutory land-allocation timelines, is the operational benchmark that the Bangladesh policy machinery has not been willing to copy.

What the new government has said it will do

The Tarique Rahman government's published 180-day priority plan identifies "uninterrupted electricity and gas supplies" as one of four priorities, alongside law and order, essential-goods prices, and railway connectivity. The plan includes a power-deal renegotiation initiative that began within weeks of the February 17 inauguration, focused on the IPP capacity-charge book and on the Adani Power contract under which Bangladesh owes approximately USD 850 million for Jharkhand-imported electricity. Government communications have framed estimated savings from the renegotiation at approximately Tk 14,000 crore in FY26.

The renegotiation track is necessary and overdue. The Tk 420 billion FY25 capacity-charge bill is approximately one percent of GDP, paid to plants substantially not dispatching. Cutting that bill by Tk 14,000 crore is a one-third reduction; cutting it sustainably to a level commensurate with the dispatched-megawatt-hours basis would be larger still. The renegotiation track 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, 2030, and beyond as gas depletes and demand grows.

The published plan also does not yet contain the items the substitution requires. There is no announced renewable-deployment target faster than the SREDA roadmap. There is no published programme to retire (rather than renegotiate) the worst-economics oil-IPP capacity. There is no commitment to a standardised solar PPA template with statutory tender cadence. The energy file in the 180-day plan reads as cost-recovery on the existing system, not as substitution to the next system.

The five-year window, restated for the current decision

The substitution timetable is no longer abstract. The Petrobangla central trajectory for domestic gas takes production from current 2,900 MMCFD to a level meaningfully below 2,000 MMCFD by around 2031 as the mature fields deplete. The LNG doubling currently underway lifts contracted import capacity from 3.5 to 7.5 Mtpa by 2027 and on toward something approaching 10 Mtpa with the land-based terminal of the early 2030s. Re-gasification capacity is expanding accordingly. The infrastructure is being built to receive the imports.

The cost is the foreign-exchange commitment. At current Brent-linked contract pricing, 7.5 Mtpa of LNG runs to approximately USD 5 to 6 billion annually; doubling beyond that adds roughly USD 4 to 5 billion more. These commitments fall on the same balance-of-payments line as the remittance inflows that have stabilised the current account. They are senior to discretionary import compression. They are denominated in dollars and indexed to oil. They form the structural floor of the trade deficit for the rest of the decade.

The alternative substitution path is the renewable-plus-storage build the country has not been willing to scale. Tender-cleared utility-scale solar PPAs in the recent Bangladesh round have priced below the variable cost alone of coal or LNG-fired generation at international prices. The 2.65-gigawatt March 2025 tender, the January 2026 523-megawatt PPA signings, and the April 2026 77.6-megawatt tender are operational evidence that the supply side responds when the demand is structured. The Tarique Rahman government's 180-day plan does not yet contain the demand structure that would scale this from sub-gigawatt to multi-gigawatt annual deployment.

The five years from May 2026 to mid-2031 are the window in which this choice is made by decision or by default. Made by decision, the substitution is renewable-led, the foreign-exchange exposure on energy import is bounded, and the post-RMG industrial diversification gets the kilowatt at the price it needs. Made by default, the substitution is LNG-led, the foreign-exchange exposure compounds, and the substitution cost lands on the same fiscal envelope that has to fund the bank cleanup, the education investments, and the climate adaptation that the rest of this series describes.

What the next six months actually decide

For the BNP government's next six months, the energy-file decisions that matter are five.

First, on the existing coal fleet, choose. Either subsidise the 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 because the capacity charges keep accruing while the kilowatt-hours do not.

Second, on the IPP renegotiation, define the principle. Capacity payments tied to dispatched megawatt-hours, not to nameplate availability. Sunset clauses on contracts entered under the 2010 to 2015 quick-rental regime. Conversion of the most stranded plants to storage-backup roles where their existing transmission interconnection has residual value.

Third, on solar deployment, set the 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 that match the Vietnamese template.

Fourth, on LNG, manage the foreign-exchange exposure. Long-term contracts at locked-in pricing, not spot-market dependency. Hedging programmes at the central bank where appropriate. Transparent reporting to parliament on the contracted LNG cost line in the budget.

Fifth, on cross-border power, accelerate rather than negotiate. 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.

None of these five components is novel. All of them have been studied in successive five-year plans and IEEFA working papers. The constraint is the political-economy bandwidth of a government in its first year, with a 180-day plan that has rightly prioritised the visible price-and-supply problem and has not yet got to the substitution architecture underneath it.

The next decade's energy stack

The Tongi spinning mill manager whose generator throttles on Thursday afternoon is one micro-observation of the substitution problem. The Matarbari duty engineer dispatching 315 megawatts is another. They are connected: the gas that the Tongi mill cannot get at the pressure it needs is the same gas that should be flowing into the Matarbari coal-substitute LNG cargo, and the substitution decision determines whether both problems get smaller or larger by 2030.

The Tarique Rahman government has bought the country time on the cost side through the IPP renegotiation and the Adani re-pricing. It has not yet bought time on the supply-substitution side. The 180-day window in which the substitution architecture can be set is half-gone by August. The country has the analytical capacity to know exactly what to do. Whether it does it is what the next six months decide.

Sources

Created: 2026-05-16 14:39:21 Updated: 2026-05-29 19:43:11