Just about a year ago, Bangladesh unveiled its Integrated Energy and Power Master Plan (IEPMP) with surprising targets – becoming a high-income country by 2041 through a fivefold economic growth powered by energy supplied from fossil fuels and the so-called clean fuels.

Emran Hossain

Just about a year ago, Bangladesh unveiled its Integrated Energy and Power Master Plan (IEPMP) with surprising targets – becoming a high-income country by 2041 through a fivefold economic growth powered by energy supplied from fossil fuels and the so-called clean fuels.

Despite its ambitious targets, the IEPMP, prepared by the Japan International Cooperation Agency, represents just a transitional phase in Bangladesh’s broader development strategy.

The immediate reaction of economists to the release of the draft of the IEPMP in 2022, which was passed almost as it was a year later in July 2023, was that its targets were impossible to achieve, especially given that none of the three previous power sector master plans formulated since 2005 went even close to achieving their goals.

The previous power sector plans instead landed Bangladesh in the worst economic crisis in decades, draining its foreign reserve to import expensive fossil fuels and pay capacity charges for an overcapacity of 100 per cent. It eventually weakened the currency, leading to staggering inflation for more than two years.

Bangladesh’s present installed power generation capacity is over 30GW, mostly based on fossil fuels. The power overcapacity entailed over Tk 1 lakh crore in capacity charge, money paid to power plants regardless of offtake, over the 14 years until August 2023. Bangladesh tried to cope with the predatory expenses by increasing the energy price by about 300 per cent over the same period and introducing rolling blackouts, up to 20 hours a day.

Energy experts were surprised by the IEPMP planning to follow almost the same path taken by the previous master plans instead of finding ways to end the crisis in which Bangladesh’s outstanding debt to power and energy companies at home and abroad stood at about $4b.

Bangladesh plans to add 11.1GW of new gas-fired capacity by 2027, mostly depending on the imports of liquefied natural gas, and 6.5GW of new coal capacity, also based on imports, by 2026.

Yet, the IEPMP did not end there. The IEPMP plans to introduce clean fuels – ammonia and hydrogen co-firing and carbon capture and storage – accounting for 40 per cent of the power generation mix in 2041 – 60GW.

Clean energy initiatives are tied to Prime Minister Sheikh Hasina’s pledge at the 2021 COP26 summit in Glasgow. While she promised that 40% of the power generation mix by 2041 would be renewable energy, the IEPMP has adjusted this goal and placed less emphasis on renewables.

The IEPMP, however, described technologies such as ammonia and hydrogen co-firing as technologies in their infancy, requiring careful investigation. Energy experts have already described these so-called clean fuels as false solutions, a means discovered by the fossil fuel industry to buy more time for its business, locking economies in costly fossil fuels.

Bangladesh plans to extend its fossil fuel thermal power generation mix almost unabated for the next decade and, then, gradually replace it with clean fuels. The IEPMP confirmed the net zero target was impossible to achieve before 2070.

The IEPMP is full of contradiction, energy experts repeatedly pointed out. But one thing the IEPMP made clear that the clean fuels were more expensive than coal and gas and unreliable but still included those fuels in the energy mix.

Bangladesh’s energy consumption is historically mostly dependent on traditional, indigenously produced biomass and locally extracted gas. The moment the country started relying on fuel import, which was in 2018, its economy immediately caved in.

Bangladesh’s per capita energy supply is 331kg in oil equivalent, below one-fifth of the world average of 1,801kg in 2020.

The clean fuel technologies raise too many questions and challenges. First of all, it will inflate energy prices, particularly because of the high cost of their derivation. Then there comes the need to retrofit existing infrastructures to enable them to use these clean fuels.

Bangladesh’s infrastructures are mostly designed to use gas. If not locally produced, the clean fuels will have to be imported, which is even more expensive than liquefied natural gas and its handling is way more complex. There are also environmental and health risks from clean fuels’ leakage during their production, transportation and use.

The IEPMP avoided deliberating on all these challenges, downplaying their significance with misleading statements that ammonia transport is not very difficult. Bloomberg NEF, the international energy research organization, released a detailed report in October last year weighing clean fuel prospects for Bangladesh in light of the IEPMP, which lays out the country’s energy plan through 2070.

Theoretically, co-firing coal with cleaner alternative fuels means replacing a portion of the coal used for power production with ammonia or biomass. Blending hydrogen with natural gas, on the other hand, involves injecting hydrogen into the natural gas fed to the gas turbine.
The replacement of fossil fuels with the cleaner fuels involves retrofitting of the existing infrastructure and adding new equipment and introducing new technologies to tackle new challenges.

Limited modifications to fossil fuel thermal power plants may enable low levels of co-firing or blending but it barely reduces greenhouse gas emissions.

Due to their low energy density, ammonia, hydrogen, and biomass need to be used in much larger volumes than fossil fuels to produce the same amount of energy, which complicates their practical application.

According to the Bloomberg report, a coal-fired power plant emits approximately 0.9 tons of carbon dioxide per MWh of electricity produced. A combined cycle gas turbine, on the other hand, releases 0.4 tons of carbon dioxide on average for generating the same amount of electricity. A coal-fired power plant would have to replace over 50 per cent of its coal or about 80 per cent with ammonia to bring its carbon dioxide emission level to that of the combined cycle gas turbine, the Bloomberg NEF said.

The Bloomberg estimated that imported hydrogen procurement could be four to five times more expensive than gas procurement and ammonia could be seven to nine times costlier than coal.

‘Reliance on such fuels would increase power prices and/or the financial burden on taxpayers depending on whether the government decides to support the higher costs of these clean fuels through a rise in regulated electricity tariffs or taxes,’ noted the Bloomberg report.

Hydrogen can be domestically produced through the electrolysis of water using clean electricity. The hydrogen then can be used for producing electricity.

Bangladesh would need to build 9.3GW of solar projects to domestically supply hydrogen to power a 1GW retrofitted combined cycle gas turbine plant, the Bloomberg NEF estimated, adding that only 2.8GW of solar would generate the same amount of electricity.

Ammonia is a hydrogen derivative. The Bloomberg NEF also estimated that 9.9GW of solar project would be needed to locally supply ammonia for a 1GW retrofitted coal power plant.

‘This is more than four times larger than solar capacity needed (2.1GW) to generate the same amount of electricity as the coal plant,’ said the Bloomberg report.

The report estimated that the marginal abatement cost for 25 per cent ammonia co-firing in 2030 would be in the range of $332-385/t-CO2. For 50 per cent ammonia co-firing, the abatement cost would be $217-295/t-CO2 in 2040 and $199-258/t-CO2 in 2050. These levies would be a huge financial burden to power plant owners and electricity end-users, the report said.

Hydrogen leakage during the production, transport and consumption would also have to be minimized, as hydrogen is an indirect greenhouse gas, with significantly higher global warming potential than carbon dioxide. Significant investment would be required to retrofit existing combined cycle gas turbines to make them compatible with high concentrations of hydrogen fuel.

Additionally, the production, transport and storage of clean hydrogen would require significant new investment.

There are three most common labels of hydrogen depending on their production methods and greenhouse gas emissions. Green hydrogen, produced through the electrolysis of water using renewable electricity, emits little to no greenhouse gases. Blue hydrogen made from steam reforming of methane or gasification of coal coupled with carbon capture and storage releases more emissions than green hydrogen. Gray hydrogen, similarly produced via steam reforming of methane or gasification of coal but without carbon capture and storage (CCS), results in significant carbon dioxide emissions. Almost all hydrogen and ammonia produced today are gray, Bloomberg noted.

Bloomberg estimated blue hydrogen imported from the Middle East would be cheaper than other hydrogen types until 2025. Green hydrogen produced in Bangladesh would become the cheapest in 2026 by undercutting the production cost of blue ammonia from the Middle East.

The costs of green hydrogen production in Bangladesh are expected to decrease as renewable electricity and electrolyser costs reduce. Imported clean hydrogen from Australia and the Middle East would cost twice or three times more than green hydrogen in Bangladesh.

The biggest cost driver behind imported hydrogen is the conversion process. The Bloomberg report assumed that hydrogen is exported to Bangladesh from Australia or the Middle East in the form of ammonia as it is the most economical shipping option. This requires ammonia synthesis using hydrogen.

Once in Bangladesh, ammonia must be converted back to hydrogen and nitrogen via thermolysis. These conversion processes are costly and increase the costs of imported hydrogen production.

Blue ammonia from the Middle East becomes the most expensive by 2036. Local green ammonia in Bangladesh would be the most expensive in the near term because of the high cost of renewables in the country.

Green ammonia imported from Australia would be cheaper than local green ammonia but costlier than blue ammonia imported from the Middle East. Production costs of imported green ammonia from Australia and local green ammonia in Bangladesh should undercut the costs of blue ammonia from the Middle East in 2033 and 2036, respectively. From 2036, blue ammonia from the Middle East would be the costliest option.

Retrofitting fossil fuel power plants to accommodate hydrogen, ammonia, or biomass blending necessitates significant investment in new equipment and facilities.

Coal retrofits with ammonia include upgrading burners and investing in ammonia storage. Controlling the exhaust nitrogen oxides (NOX) emissions will be key in each plant’s combustion strategy. Coal retrofits with more than 20 per cent ammonia co-firing have not been tested or commercialized.
The higher the ammonia co-firing ratio the higher the need for upgradation and equipment replacement.

Storage tanks for ammonia would also need to be bigger at a higher co-firing ratio. More advanced equipment to capture NOX emissions would be needed as well. Hydrogen combustion also requires new equipment, including more resilient materials to sustain higher temperatures. It also necessitates increased operations and maintenance for managing these temperatures and the heightened use of water for cooling.”

To achieve significant carbon dioxide emission reduction from a thermal power plant, the ratio of hydrogen to natural gas and ammonia to coal must be very high. The main challenge lies in deriving the hydrogen and ammonia in a low-emission manner.

Combustion of fuels such as ammonia or hydrogen at high temperatures leads to NOx emissions. Since hydrogen and ammonia burn hotter than fossil fuels, the nitrogen and oxygen in the air react at a higher rate, leading to more NOx emissions. These combustion technologies also emit Nitrous Oxide (N2O) – a greenhouse gas. The global warming potential of nitrous oxide is 273 times greater than that of carbon dioxide over a 100-year timescale.

Zero emission is only possible when a combined cycle gas turbine uses 100 per cent green hydrogen. If the green hydrogen use ratio stays 50 per cent it halves carbon dioxide emission to 0.20 tons per MWH of electricity generated, compared to emissions from a gas-based power plant.
Blue and gray hydrogen can never achieve zero emissions.

The use of 100 per cent gray hydrogen increases carbon dioxide emissions compared to emissions from power plants run with natural gas. 100 per cent use of blue hydrogen will still emit 0.05 tons of carbon dioxide per MWH of electricity generated. Similarly, only 100 per cent use of green ammonia can achieve zero emission. At 50 per cent green ammonia co-firing, carbon dioxide emission halves to 0.45 tons per MWH of electricity produced.
A coal power plant emits 0.90 tons of CO2 for generating an MWH of electricity. A hundred per cent use of gray ammonia slightly reduces CO2 emission to 0.79 tons per MWH. 100 per cent use of blue ammonia can reduce emissions to 0.08 tons per MWH.

The Bloomberg NEF noted no emission in solar and onshore wind technologies. Their report estimated that the average cost for producing an MWH in 2030 with 100 per cent hydrogen would be $257, slightly below $296 would be needed to generate the same amount of power using 100 per cent ammonia.
In 2030, the production cost of an MWH of power from a combined cycle gas power plant using natural gas would be $94. Using coal the price for producing the same amount of electricity would be $118. The cost of producing the same amount of electricity from solar with battery storage would cost $87 while from the onshore wind with storage would cost $116.
In 2050, the cost of solar power would drop to $52 and onshore wind to $62 per MWH but the coal and gas power cost will remain the same. The cost of generating an MWH from 100 per cent hydrogen and ammonia would hover around $200, the Bloomberg NEF report estimated.

The dangers of ammonia and hydrogen extend beyond their clean energy potential, posing significant safety risks due to their high flammability. At a poultry plant in China’s Jinlin province, ammonia leakage caused a fire and killed 120 people in 2013. In 2017, hydrogen leakage from a coolant at a coal-fired power plant in Ohio in the US caused an explosion that killed one person and injured 10.

Since hydrogen does not have distinct odors and colors, hydrogen leaks are difficult to detect. Ammonia is also highly toxic. The molecule reacts with water to form ammonium hydroxide, which is corrosive and damages cells in the body on contact. While ammonia leaks are easier to detect due to odor, contact with ammonia can be fatal from acute poisoning from inhaling. It can also cause skin, eye and respiratory damage.

Retrofitting an existing thermal power plant with CCS can be costly depending on proximity to the carbon storage site. Current CCS technologies also do not capture 100 per cent of emissions. Unless designed from the beginning, adding CCS technology to an existing thermal power plant could encounter technical and logistical complexities. And not every thermal power plant can be economically retrofitted with CCS.

Implementation of the technology requires the availability of carbon storage sites such as depleted oil and gas fields or saline aquifers at appropriate depths. A carbon capture and storage project typically target a 90% carbon capture rate which is never achieved.