India eyes green hydrogen bunkering at major ports by 2035
India has set a deadline of 2035 to establish green hydrogen bunkering and refuelling facilities at major ports in the drive to cut its carbon footprint, the shipping ministry said in guidelines issued on Wednesday. One of the world’s biggest emitters of greenhouse gases, India aims to cut emissions to net zero by 2070, and the shipping minister said three of its ports would initially have bunker facilities for green hydrogen and ammonia. “Our target is to cover all 12 major parts with a green hydrogen bunkering facility by 2035,” Shipping Minister Sarbananda Sonowal told Reuters. The initial ports in the effort are to be Paradip in the east, Kandla in the west, and Tuticorin in the south. “Financing required to turn these ports into green ports is under consideration,” Sonowal added. More than 200 ports dot India’s coastline, which stretches 7,500 km (4,660 miles), in addition to the 12 major ones, all together accounting for 95% of its trade by volume and 65% by value. Authorities want electricity to power at least half the vehicle and equipment needs of major ports by 2030, rather than diesel, and raise that figure further to 90% by 2047. “Whatever initiative we are taking aims to meet the 2070 goal of being a net-zero carbon nation,” Sonowal said. To meet the net-zero goal, at least 40% of India’s electricity will have to come from renewables. To that end, the new shipping guidelines require ports to satisfy at least 60% of electricity needs through renewables by 2030 and 90% by 2047. Also, by 2030, all ports must achieve cuts of more than a fifth in energy consumption on each tonne of cargo versus 2023, the guidelines show. To boost use of gas, the shipping ministry wants ports to set up at least one liquefied natural gas (LNG) bunkering station by 2030 and electric vehicle charging stations in and around port areas by 2025.
GAIL plans $4.9 billion ethane cracker in West India
AIL (India) Ltd, the country’s top gas supplier, plans to build a 400-billion rupee ($4.89 billion) ethane cracker near its liquefied natural gas (LNG) import plant in Western India, two sources with direct knowledge of the matter said, as it seeks to meet an expected surge in demand. Indian companies are boosting their petrochemical production capacity as the expanding economy boosts the need for goods ranging from plastics to paints and adhesives. A cracker produces ethylene, required for products such as plastics. Demand for petrochemicals could nearly triple by 2040, according to estimates by top refiner Indian Oil, forcing companies to make big investments to set up new facilities across the country. GAIL is looking for land in the coastal region of Dabhol in Maharashtra state for the 1.5 million tonnes a year (mtpa) cracker project, one of the sources told Reuters. GAIL operates a 5 mtpa LNG plant at Dabhol. The company plans to import ethane from the United States for the project, the source said. GAIL’s communications office did not immediately respond to a request for comment.
S&P says India will import lesser crude oil this year than expected
Standard & Poor’s expects India to import less crude oil than expected because of flat demand in April. Latest government data shows that oil products demand fell 360,000 barrels per day (b/d) on the month in April 2023. According to data released by the oil ministry’s petroleum planning and analysis cell, year-on-year crude oil demand was up by only 11,000 b/d, or 0.2%, marking it the weakest growth since the contraction in January 2022. The April slump was due mainly to the weakness of LPG, gasoline, and other minor products such as pet coke and asphalt. Demand for gasoil was robust with growth at 156,000 b/d, while growth for naphtha, gasoline, kerosene/jet fuel and fuel oil were more modest, but these increases were largely offset by a decline of 227,000 b/d for minor products. According to JY Lim, Oil Analyst at S&P Global Commodity Insights, India’s gasoline demand rebounded above pre-COVID-19 levels in 2021 and was expected to be some 17.6% higher in 2023. Gasoil demand was expected to be close to 8% above pre-COVID-19 levels this year, but kerosene/jet fuel demand will remain about 19% lower than 2019 levels.
Oil Price Volatility Will Only Get More Extreme
Concerns about the economy and new banking sector jitters have sent oil traders rushing for the exits and cutting their bullish bets on crude oil again. As more speculators leave the market – with open interest in U.S. crude oil futures at its lowest in three years – prices are set for more extreme volatility. WTI Crude, the U.S. benchmark, saw the biggest drop in the net long position – the difference between bullish and bearish bets – in six weeks in the week to May 2, data from the U.S. Commodity Futures Trading Commission (CFTC) showed on Friday. The previous large drop in bullish bets had taken place right before early April when the OPEC+ group surprised the oil market by announcing additional cuts to production between May and December 2023 to ensure the “stability of the market.” The OPEC+ move burned the short sellers, following through with the proverbial promise of Saudi Energy Minister Prince Abdulaziz bin Salman from 2020, “I’m going to make sure whoever gambles on this market will be ouching like hell.” After the production cuts were announced, prices spiked for two weeks until the middle of April, before negative sentiment about the economy and underwhelming Chinese recovery took over again and drove prices back down to the low $70s. WTI Crude even fell below the $70 a barrel mark last week. Speculators have been consistently caught off-guard in the past two months, and many have now opted to stay away. Lower open interest and liquidity in the market is bound to make price swings even more extreme, according to analysts. “In short, the oil market needs more players on the field,” Michael Tran, managing director at RBC Capital Markets, told Bloomberg. But in the week to May 2, money managers cut their long positions and added short positions, cutting their net bullish bets in both WTI Crude and Brent Crude futures and options contracts, data from exchanges showed. Driven by heavy selling in energy, bullish bets on the major commodities futures plunged by one-third in the latest reporting week to the lowest since June 2020, Ole Hansen, Head of Commodity Strategy at Saxo Bank, noted. Brent, WTI, and European gasoil – the proxy for diesel – were the hardest hit by selling. The technical downside break forced speculators to cut their net long position in WTI Crude by 36,000 lots and in Brent by 69,000 lots in the week to May 2. The combined net long position in the two most important crude oil futures and options contracts was slashed by one-fourth, while the net short position in ICE gasoil futures continued to swell to a fresh high in more than seven years. “A nightmare two-month period for momentum traders continued in the week to May 2,” Hansen commented. “During an eight week period the crude oil market has seen a banking crisis, an Opec cut driving a spike and subsequent focus on gap closing, and fresh demand concerns,” he added. Speculators have responded by selling 393,000 lots and buying 213,000 lots, the bulk of these at unprofitable levels, according to Saxo Bank’s head of commodity strategy. The economy in the U.S., the pace of the Chinese recovery, and the upcoming OPEC+ meeting in early June will continue to drive oil markets, while fresh bank runs could quickly sour sentiment again in the coming weeks. Reports emerged last week, when oil prices crashed again, that OPEC+ would hold its June 4 meeting in person. The last time OPEC+ ministers met in person in Vienna was in October 2022, when the alliance announced oil production cuts from November 2022 through December 2023. In the meantime, speculators and momentum traders could be more careful with bets in the oil market, which would leave prices exposed to wild swings in either direction.
India govt panel proposes ban on diesel 4-wheeler vehicles by 2027
India should ban the use of diesel-powered four-wheeler vehicles by 2027 and switch to electric and gas-fuelled vehicles in cities with more than a million people and polluted towns in order to cut emissions, an oil ministry panel is recommending. India, one of the biggest emitters of green house gases, wants to produce 40% of its electricity from renewables to achieve its 2070 net zero goal. “By 2030, no city buses should be added which are not electric…diesel buses for city transport should not be added from 2024 onwards,” the panel said in a report posted on the oil ministry’s website. It is not clear if the petroleum ministry will seek cabinet approval to implement the recommendations of its Energy Transition Advisory Committee, headed by former oil secretary Tarun Kapoor. To boost electric vehicle use in the country, the report said the government should consider “targeted extension” of incentives given under Faster Adoption and Manufacturing of Electric and Hybrid Vehicles scheme (FAME) to beyond March 31. Diesel accounts for about two-fifths of refined fuel consumption in India with 80% of that being used in the transport sector.
ONGC to pump KG block oil by June, ending 3-yr delay
Oil and Natural Gas Corp. Ltd (ONGC) is set to begin oil production in the Krishna Godavari basin by June, said Om Prakash Singh, ONGC’s director of technology and field services (T&FS) in an interview. The company’s oil production from the block was scheduled to begin by March 2020, and gas by June 2019, but was delayed due to the pandemic.
Middle East gas producers set to spend $120bln to boost output by 2030
The Middle East is set to spend up to $120 billion to boost natural gas production by more than 19% by 2030, according to energy consultancy Wood Mackenzie. Natural gas output from the region will rise to 86 billion standard cubic feet (bcfd) a day by the end of the decade, from 72 bcfd currently, it said in a report last week. The expected increase in production is equivalent to the gas consumption of the entire European power sector and could help energy companies solve the energy trilemma of sustainability, security and affordability, the report said. “The Middle East can be part of the solution for the global gas markets as the region continues to ramp up production from its gigantic gas reserves,” said Alexandre Araman, principal analyst for Middle East Upstream at Wood Mackenzie. Around half of the 14 bcfd increase will be made available for export, which could have a game-changing effect on the global gas markets, especially as the LNG liquefaction capacity in the Middle East keeps growing. The other half will be absorbed by domestic demand growth. “To fulfil the level of production growth that we have predicted, investments in non-associated gas projects are set to reach a record $25 billion this year and a cumulative total of $120 billion by the end of the decade.” Qatar LNG exports should reach 126 million tonnes per annum (mmtpa) by 2030, while Abu Dhabi should be able to export 15.4 mmtpa after its new LNG facility comes onstream in 2028. The report adds that for international companies, gas projects in the region present attractive opportunities. Gas accounts for barely 35% of their Middle East production mix but generates more than 70% of the value. Fifty per cent of the value figure is created in the global LNG powerhouse of Qatar by three companies: ExxonMobil, Shell and TotalEnergies.
India’s IGL partners Acme for H2 infrastructure
Indian state-controlled city gas distributor Indraprastha Gas (IGL) has signed an initial agreement with Indian renewables firm Acme to develop domestic green hydrogen infrastructure. The companies will work together to explore opportunities for setting up hydrogen generation plants, including electrolysers to blend green hydrogen in IGL’s existing pipeline networks supplying gas to households and industrial and commercial set-ups, as well as compressed natural gas (CNG) for vehicles, IGL said on 4 May. IGL operates a 18,811km pipeline network across Delhi’s national capital region. The companies will also co-operate in policy matters and promote adoption of green hydrogen and green ammonia to customers. IGL is also looking at opportunities for green hydrogen use in the automobile sector and production of green ammonia from green hydrogen, said managing director Sanjay Kumar. Blending green hydrogen into city gas-distribution networks is a key component under the first phase of India’s National Green Hydrogen Mission, which runs until 2026. The scaling up of green hydrogen production and use should drive down costs, allowing for greater and wider deployment in the second phase that is scheduled to run until 2030. Then the government will seek to make green hydrogen costs competitive with fossil-fuel alternatives for refineries and fertilizer production, exploring commercial-scale green hydrogen-based projects in the steel, mobility and shipping sectors. The government aims to make India “the global hub for production, usage and export of green hydrogen and its derivatives”, according to the National Green Hydrogen Mission policy document, with an intention to reach 5mn t/yr of green hydrogen production by 2030. Indian state-controlled gas distributor Gail has already begun blending grey hydrogen with natural gas to be supplied to Avantika Gas, its joint venture with state-controlled refiner Hindustan Petroleum. Gail launched the hydrogen blending project as a pilot venture, seeking to establish the feasibility of blending hydrogen into the city gas distribution network. It aims to subsequently replace grey hydrogen with green hydrogen. Gail has successfully blended up to 2pc of hydrogen in natural gas in the city gas network, it said last year. State-controlled power utility NTPC also has started blending green hydrogen into the piped natural gas (PNG) network of gas distributor Gujarat Gas. The joint venture is equipped with a 6.5kW polymer electrolyte membrane electrolyser powered by a 1MW floating solar power unit, the first of its kind in India, according to a NTPC official. Hydrogen can be blended with natural gas for industries such as ammonia, refining and methanol and into natural gas pipelines for the existing city gas network of PNG and CNG, according to a report by government think-tank Niti Aayog. The blending of hydrogen into city gas distribution is currently at the nascent stage as the government is experimenting and monitoring its outcome. There is a limit to blending hydrogen in existing pipeline infrastructure because of its low density and higher diffusivity, as existing gas pipelines should be coated or made of different material to withstand higher compression ratios, the report added.
Green hydrogen: State oil firms target 38,000 tons/year capacity by 2024-25
India’s state-run oil and gas companies are targeting to build a combined green hydrogen generation capacity of 38,000 tonnes per annum by the next financial year, according to a government panel report The planned green hydrogen facilities would require setting up a combined electrolyzer capacity of 279 MW by 2024-25, according to the energy transition advisory committee of the petroleum ministry. Of this, Hindustan Petroleum is planning to have 115 MW capacity at its refineries in Visakhapatnam and Barmer. Gas pipeline operator GAIL is targeting a capacity of 60 MW while Indian Oil, the nation’s largest refiner, aims to develop a capacity of 56 MW at its Mathura and Panipat refineries. Bharat Petroleum is targeting 25 MW capacity while Numaligarh Refinery and Mangalore Refinery& Petrochemicals are aiming for 20 MW and 3 MW respectively. India is placing a big thrust on green hydrogen in its energy transition plan. It aims to develop green hydrogen production capacity of at least 5 million metric tonnes per annum by 2030.
Is Clean Energy Really More Expensive Than Traditional Energy?
Judging from the news story, a PR firm had an assignment: to inform the world that clean energy prices exceed dirty energy prices, just as Republicans in Congress try to repeal large parts of the Inflation Reduction Act (which boosts clean energy). Maybe a coincidence. Politics is not our area of expertise. But the arguments that were made sure read like talking points that politicians repeat in cable news interviews: Clean new industries will need workers, especially engineers, and won’t get them by raiding staff from fast food restaurants. This is true, of course. The new industries will have to compete for experienced workers, attract American students into engineering, entice engineers from abroad, and offer competitive wages. The old industries will have to compete for the workforce with the new industries. That’s what happens in markets. The new policies will upend our decades-long dependence on global markets to provide goods and services at the lowest prices. Well, isn’t the point of going local to protect our national security? Extra security costs money, just as insurance does. So, do you want security or low prices? Government handouts to particular technologies distort the market. Economists agree that the least market-distorting way to deal with the problem is to tax carbon and let the market figure out how to reduce emissions. But let’s be realistic. Congress will not approve any new tax. So Biden had the choice of a sub-optimal policy or doing nothing. As Voltaire said, “The perfect is the enemy of the good.” These dazzlingly unhelpful bullet points don’t mention a principal reason why clean energy prices may exceed dirty energy prices: the latter do not include costs borne by society, not the producer or user. If the cost of damage to health or the environment were included, the dirty product might cost as much as or more than the clean product. So, switching to a clean product might affect the price paid but not the cost to society. Marketers and product developers might brush off the argument altogether. New products often sell for more than seemingly similar old products. Consumers who want to be first on the block willingly pay more, especially for a product they see as different. And the cost and price of new products decline as producers attain economies of scale. What’s the big deal, then? Maybe a big part of the problem is that incumbent energy companies, which have political influence and money don’t spend much on research and development, relatively speaking, do not develop new products and will lose out if the new competitors succeed. So they have every reason to lobby against the new competitors, especially if the government is giving them a boost. ExxonMobil, Shell, and Chevron, between them, spend only 0.3% of revenues on research and development, and the electricity and natural gas industries in the United States around 0.1% of revenues. On the other hand, automotive giants General Motors and Ford, together, spend 5% of revenues on research and development, and fuel cell manufacturers Bloom Energy and Plug Power 13%. Our point is not that when you don’t spend on your future, you might not have one, but rather if you don’t spend on improving your products you may not find ways to reduce their costs or improve their attractiveness, while your competitors are doing just that. Projections show a continued decline in the costs of alternative energy that will soon bring them below legacy energy costs. But that analysis does not take into account any number of projects that could disrupt the energy market even more: Co-fire fossil fuel plants with ammonia. (A project that involves major Japanese utilities and global ammonia producers.) Improve perovskites, which could substantially reduce solar costs and revolutionize its uses. (Work ongoing in China and USA.) Turn hydrogen into the new storage, fuel, and energy transfer medium. (Huge projects underway throughout the world.) Establish the existence of commercial deposits of renewable hydrogen underground. (A small-scale Australian enterprise with potentially big prospects.) Demonstrate via an expensive exploratory drill hole in Utah the possibility that we can tap deep, dry rock geothermal energy (enough to replicate the U.S. generating fleet 500 times over). Build superconductor grids to connect renewable energy. (A European energy firm wants to do just that, arguing that the existing grid cannot do it. What about here?) Any of these possibilities could dramatically raise the prospects for decarbonization, largely by improving the cost and reliability of electrification. We would get a better notion of future costs by looking forward not backward.