In May this magazine argued that the Hormuz crisis had not created Bangladesh’s vulnerability but revealed it, and asked what it would take to be less exposed. The strait has since reopened and oil has fallen back below $80. What has not eased is the cost, and a message from Doha in July shows why the answer to that question still matters.

BBF RESEARCH DESK

Earlier this month, QatarEnergy sent a message to Rupantarita Prakritik Gas Company Limited, the arm of Petrobangla that buys the country’s liquefied natural gas. Bangladesh’s largest supplier said it may deliver only half the cargoes it is contracted to provide in 2026, twenty instead of forty, and that the reduced level could persist for the next three to five years.

The strait was open when that message was sent. The ceasefire was holding and oil was falling. Yet one of Bangladesh’s most important energy relationships was being reshaped in a way that will outlast the conflict that triggered it.

This is the part of any crisis that receives the least attention, because it happens after the headlines move on. The war ends, the price of Brent comes down, and the invoices from the disrupted months arrive later.

How the bill was run up

The sequence began on 2 March, when QatarEnergy invoked force majeure, the contractual clause that allows a supplier to suspend its obligations when something extraordinary prevents delivery. Oman’s OQ Trading followed on 5 March. The American firm Excelerate Energy followed on 6 March. Within five days, every one of Bangladesh’s long-term LNG suppliers had walked away from its contracts at once.

Under the Annual Delivery Plan for 2026, Bangladesh was to import 115 cargoes, of which only 17 were meant to come from the spot market. Between March and June the country had planned 41 cargoes with just 8 bought on spot. What actually happened was that Petrobangla managed 37 cargoes in total, and 25 of them had to be bought at whatever the open market was charging that week.

Source: Petrobangla, as reported by The Business Standard. The country bought roughly three times the spot volume it had budgeted for.

The open market was charging a great deal. Bangladesh had been buying spot cargoes at around $10 per mmBtu in January. By mid-March it was paying $28.28. Across the crisis, the spot purchases came in at between $20 and $28, average at roughly $21. Had the war not happened, those same cargoes would have arrived under long-term contract at somewhere between $9 and $11.

Bangladesh spent the spring buying its own gas at two to three times the price it had contracted to pay for it.

AKM Mizanur Rahman, director of finance at Petrobangla, gave The Business Standard the number without decoration. The Iran war, he said, cost the country an additional Tk 10,600 crore because most long-term suppliers maintained force majeure from March onward, forcing Petrobangla into expensive spot purchases. The total LNG subsidy requirement for the financial year has climbed to Tk 16,600 crore against an original allocation of Tk 6,000 crore. The government has already handed over Tk 13,100 crore of it.

“The Iran war cost us an additional Tk 10,600 crore.”
AKM Mizanur Rahman, Director (Finance), Petrobangla

Why the reopening hasn’t lowered the bill yet

A ceasefire reopens a waterway. It does not, on its own, reset the cost of using it, and the gap between those two things is where this story now sits.

The United States and Iran signed a memorandum on 14 June, in force from 18 June, and the strait reopened to commercial shipping. Brent, which had gone from $72 at the end of February to $118 by the end of March in the largest monthly increase on record, settled at $76.01 on 11 July. Morgan Stanley has cut its oil forecast twice in two weeks and is now warning of a glut rather than a shortage.

And yet the ships have not come back. Vessel traffic through Hormuz, which ran at roughly 130 commercial transits a day before the war, remains around 70 percent below pre-war levels weeks after the reopening. Gulf sea freight rates sit 40 to 60 percent above pre-crisis levels. Maersk, MSC and CMA CGM are still routing around the Cape of Good Hope.

The reason is insurance, and it is the most underreported mechanism in global trade. War-risk premiums for a Hormuz transit ran at about 0.25 percent of a vessel’s hull value before the conflict. They rose to somewhere between 3 and 8 percent. For a tanker worth $150 million, that turns an insurance bill of roughly $375,000 into one of several million dollars, for the same ship carrying the same cargo along the same water.

Then comes the arithmetic that explains everything else. At a war-risk premium of around 2 percent, sailing through Hormuz and sailing all the way around the Cape of Good Hope cost a shipowner roughly the same per voyage. At 3 percent or above, the Cape is cheaper, despite adding some three weeks at sea. Once the premium crosses that line, the strait is open in the legal sense and closed in the only sense that matters.

The strait is not being held shut by mines any more. It is being held shut by underwriters.

Lloyd’s Joint War Committee, which designates the high-risk zones that trigger these premiums, does not price the risk of today. It prices the tail. A single vessel lost in Hormuz could generate claims of hundreds of millions of dollars, so underwriters want independent hydrographic certification that the mines are gone, restored reinsurance capacity, and a sustained run of sixty to ninety days without an incident. Iran’s Revolutionary Guard fired missiles at ships near the strait on 7 July. The clock keeps resetting. Brokers now expect the designation to begin easing in the final quarter of 2026, with normal cover unlikely before the first half of 2027.

Who actually paid, and who collected

A closed chokepoint does not destroy demand for oil and gas. It relocates the profit from meeting it.

An analysis by The New York Times comparing trade from the start of the war to 8 May found that the largest beneficiaries were the United States, with roughly $50 billion in additional export revenue, and Russia, which held its exports steady and gained more than $15 billion. Every Gulf producer saw exports fall. But the ones with a way around the strait came through it intact. Saudi Arabia moved crude through its pipelines to the Red Sea. Oman simply sits on the outside of the bottleneck. Iraq, Kuwait, Qatar and the United Arab Emirates, with no overland alternative, watched their revenue decline.

Sources: New York Times trade analysis (to 8 May 2026); Petrobangla. Infrastructure, in this crisis, functioned as insurance.

That is the lesson of the whole episode compressed into a single table. The countries that had spent money on a bypass before they needed one were paid back in a single quarter. The countries that had not were charged for the omission. Bangladesh sits at the far end of that chain, buying from suppliers who were themselves cut off, and so inherited the cost without ever having had a seat at the table.

What May asked, and what August answers

This magazine argued in May that Bangladesh’s exposure reflected an energy strategy built on imported hydrocarbons routed through a single chokepoint, with limited strategic reserves and a still-small renewable base. Three priorities followed from that: diversifying the energy mix, diversifying supply routes, and building strategic reserves. All three are long-lead undertakings, the kind that take years of investment before they show up in the numbers, and that work is still in its early stages.

The underlying figures reflect that timeline. Domestic gas fields produce around 1,700 to 1,800 million cubic feet a day, down from roughly 2,500 in 2018. Imported LNG supplies about 35 percent of gas demand, and more than 70 percent of that LNG originates in Qatar. Renewables account for under 3 percent of grid generation. Total supply runs near 2,650 million cubic feet a day against demand above 4,000. These are the starting conditions any diversification effort has to work from.

The region offers a useful reference point for what that work can achieve. Pakistan’s distributed solar capacity reached 34,000 megawatts in 2025, cutting grid demand by 11 percent against 2022 and contributing to a 15.4 percent fall in the country’s LNG demand in a single year. India’s gas share of generation has drifted down from 10 percent in 2013 to 7 percent in 2024 as solar and wind scaled. Both built that resilience before they needed it, which is the pattern that pays off, and both show the scale of change that is achievable within a few years once the investment is made.

There are signs of movement on the contract side too. The Energy Division has formed a five-member committee to review the force majeure provisions in the LNG contracts and to examine whether agreements with suppliers still invoking the clause can be renegotiated. The review has a reasonable case to work with: several of these suppliers are traders rather than producers, buying gas and reselling it, and none of their own facilities were struck. Invoking force majeure while the strait was shut was defensible; the question now is how quickly deliveries return to contract terms as conditions normalise.

The exposure that outlasts the crisis

There is a good deal in this story that points to recovery. Oil is back under $80. The ceasefire is holding. The ships are moving again, if slowly. The Boro harvest came in and the load-shedding eased. The acute phase is genuinely passing.

What the QatarEnergy message shows is that the structural part takes longer. A supplier signalling reduced deliveries over three to five years is responding to something that a reopened strait does not fix on its own: damaged production takes years to rebuild, insurance markets normalise more slowly than shipping lanes, and refiners who found new suppliers during the closure are in no hurry to switch back. Trade routes that re-wire themselves during a shock tend to stay re-wired for a while after it.

In May the question was what it would take to be less exposed. The value of asking it now is that the honest answer is visible: Bangladesh’s underlying position is much as it was in February, one main waterway, one dominant supplier, a renewable base still under 3 percent, and limited reserves. That is also the case for acting on the diversification the last five months have made concrete rather than theoretical. The cost of this episode is the clearest argument yet for the investment that would blunt the next one.