Biofuels in India: Do the Benefits justify the Costs?
According to projections by the IEA (International Energy Agency), India is expected to overtake China to become the third largest producer of ethanol by 2023. In 2016, India was seventh in the list of top ethanol producers and by 2021 it overtook Germany, Thailand, and Canada to become the fourth largest producer. In 2022, India is likely to match ethanol production from China and by 2023 overtake China to claim the third spot after the USA and Brazil. The spurt in ethanol production in India is almost entirely policy driven. The most recent policy push on which the IEA’s optimistic projections for ethanol production from India are based come from the target set by the 2021 report on ethanol blending by Niti Aayog and the Ministry of Petroleum & Natural gas (MOPNG).
Among key recommendations of the report are that the MOPNG mandate 10 percent ethanol blending (E10) in petrol throughout the country by April 2022 and roll out 20 percent ethanol blending (E20) in petrol in a phased manner by April 2023. This brings forward the target set by the national policy on biofuels 2018 which recommended an indicative target of E20 blending in petrol and 5 percent blending of biodiesel (B5) in diesel by 2030. The 2021 Niti Aayog report is a step backwards from a technology perspective as it has renewed the focus on biofuels that rely on food-based feedstocks, while the 2018 policy emphasised biofuels that rely on non-food biomass. The return to biofuels based on food-based feedstock has reignited the food versus fuel debate with many environmental organisations criticising the move.
The two biofuel types that dominate production today are sugar-based bioethanol production and vegetable oil or fatty acid methyl ester (FAME) based biodiesel. Most of the first generation biofuels (1GB, primarily bioethanol and biodiesel) are sourced from food-based plants that have energy-containing molecules like sugars, oils and cellulose. Since 2000, the share of biodiesel in total biofuel production has increased nearly ten-fold, from 3.3 percent in 2000 to nearly 32 percent in 2020, but bioethanol still accounts for two thirds of total production. Biofuel yield from 1GBs is limited and it has a negative impact on food security. Second generation biofuels (2GB) use feedstock of lignocellulosic (non-starch based fibrous part of plant material) that include straw, bagasse, forest residues (all non-food) and purpose grown energy crops on marginal lands. There are very few commercial scale 2GB production operations today. Third generation (3GB) biofuels are algae based and carry the potential to provide a non-food, high-yield, non-arable land use source of biodiesel, bioethanol, hydrogen etc. 3GBs are in the research and development stage. Research on fourth generation biofuels (4GB) or photobiological solar fuels and electro fuels that directly convert solar energy into fuel using raw materials that are inexhaustible, cheap and widely available is in its early stages.
The USA is the largest ethanol producer in the world accounting for 46 percent of global production and the second largest in biodiesel production accounting for 19 percent of production. 87 percent of bioethanol production in the USA is corn based. Brazil is the second largest ethanol producer in the world accounting for 28 percent of global production and 14 percent of biodiesel production. Brazil’s ethanol is derived from sugarcane and its biodiesel from soyabean. The European Union is the world’s largest biodiesel producer but most of it is produced from imported feedstock. Globally, biofuels accounted for 0.2 percent of total primary energy consumption and 0.7 percent of transportation energy consumption in 2019. In India the share of biofuel consumption in total primary energy consumption was roughly the same at 0.2 percent and its share in transportation was 0.7 percent.
Biofuels offer both advantages and disadvantages in terms of environmental, economic and social sustainability. Reduction in greenhouse gas (GHG) emissions, energy security through lower import of crude oil and rural development are the most important drivers for biofuels globally. These are the same benefits that the report by Niti Aayog offers: increase energy security as it could potentially reduce import of crude oil, increase participation of local entrepreneurs and sugarcane farmers in the energy economy and decrease vehicular emissions. While the benefit to farmers is unambiguous because increase in demand for any agricultural crop, not just biofuel crops will benefit farmers, the energy and environment benefits are somewhat ambiguous and highly context specific.
The overall energy ratio (OER) or the ratio of the energy delivered by the fuel (petroleum or biofuel) to the sum of all energy inputs going into its production is highest for petrol and lowest for cellulosic ethanol. But as the energy input for biofuels is mostly renewable, the fossil energy ratio (FER) which is the ratio of the liquid energy output to the fossil energy input is lower. For petrol, the FER is the same as that of its OER at about 0.8 and about 10 for Brazilian sugar cane-based ethanol. The FER is high for sugar cane-based ethanol because most of the energy input to produce ethanol comes from sugarcane fibre. Estimates on the FER for Indian ethanol are not available, but it is likely to be lower than that of Brazilian ethanol because Brazilian ethanol is rated as the most energy efficient among biofuels in many studies.
The report from Niti Aayog quotes potential reduction of GHG emission at the point of use, that is from the tailpipe of vehicles, to make its case for ethanol blending. But life cycle assessment (LCA) studies have considered the carbon mitigation and other environmental impacts of biofuels over its full lifecycle, from plant to fuel. The findings are often conflicting, with a wide variation in the estimates. One reason for the wide variation is the difficulty in estimating net carbon emissions from land use change involved in biofuel cultivation. All plants and trees are carbon sinks as they absorb carbon-di-oxide (CO2) from the atmosphere through photosynthesis. Burning biofuels in vehicles releases CO2 back into the atmosphere but as regrowth of new biofuel plants balances the emission of CO2, biofuels are, in theory, carbon neutral. But if the land used to grow biofuel crops was a forest which had to be cleared to cultivate biofuel crops, then it removes a huge carbon sink which means the biofuel thus produced is not necessarily carbon neutral. Forest clearing or land use change (LUC) as it is referred to in academic literature, substantially reduces the environmental benefits of biofuels. For example, the constant increase in demand for sugarcane based ethanol from Brazil has meant extensive deforestation of rainforests resulting in GHG emissions from Brazilian ethanol use that was about 60 percent higher than that of petrol.
For the Indian context the LCA study on corn-based ethanol production and soyabean based biodiesel production from China may be more relevant. The study found that GHG emissions from Chinese ethanol and biodiesel was 40 percent and 20 percent higher than petrol and diesel respectively because of the relatively higher use of fertilisers, higher process energy consumption and the coal dominated energy mix. If LUC related GHG emissions are not counted, then GHG emissions from most 1GBs is in the range 3 to 111 grams CO2 eq per MJ (carbon-di-oxide equivalent per million joules) which is lower than that of petroleum-based fuels. However, if LUC is considered, many of the biofuels in use in climate conscious regions such as the EU (European Union) are found to be much higher than that of petrol and diesel.
Commentary that followed the release of Niti Aayog’s report on biofuels have highlighted the potential food security and water challenges posed by the revised targets for ethanol blending. Sugarcane is a water intensive crop grown on land meant for food production and it is easy to see how the competing demands from the fuel sector could threaten both water and food security. The response that only surplus sugarcane and rice are diverted to fuel production may not hold in the longer term. Higher than anticipated rainfall from the monsoons that underpin surplus food grain production cannot sustain an ambitious ethanol blending policy for the future. India is currently a net importer of ethanol as acknowledged in the report by Niti Aayog which means that it is yet to contribute to increase in energy security. If domestic production does not increase, targets for ethanol blending can be met only by increasing imports. Increase in domestic production will remain a challenge and may come only at the expense of food security as arable land is scarce for a significant increase in domestic production of biofuels. The gains in tailpipe emissions from ethanol blending are not only too small but also redundant given India’s goal for electrifying surface transport. Benefit to farmers and rural economies from biofuel production is the key political driver of biofuel production across the world. For resource challenged India, this may bring only few benefits at very high cost.
Oil and Natural Gas Corporation (ONGC) is seeking a minimum price of US$3.5-4/mmBtu for the natural gas it plans to produce from coal seams in Jharkhand and a field in Tripura. ONGC has issued separate tenders seeking buyers of 0.02 million metric standard cubic meter per day (mmscmd) of coal-bed methane (CBM) it plans to produce from the North Karanpura CBM block in Jharkhand and 0.1 mmscmd from Khubal field in Tripura. For the CBM gas, it asked buyers to quote a percentage equal to or higher than 8 percent of Dated Brent Price, according to the tender document. ONGC has been complaining that the government-notified gas price is way below cost and the company incurs a loss of production and sale of natural gas from most of its fields. Earlier this year in April, ONGC had sought bids for the sale of an initial 2 mmscmd of gas from its KG basin fields. It had sought bids indexed to Brent crude oil for the gas from the KG-DWN-98/2 or KG-D5 block, which sits next to Reliance Industries Ltd (RIL)-BP Plc-operated KG-D6 fields in the Bay of Bengal. In the latest tender, ONGC has mentioned a 3 to 5-year sale tenure for CBM gas, with supplies commencing with immediate effect. ONGC owns 55 percent in the North Karanpura CBM block in the Ranchi district of Jharkhand. Indian Oil Corporation (IOC) holds 20 percent and Prabha Energy Pvt Ltd the remaining 25 percent. For Khubal field, the gas supplies are to begin from April 2024 and bids have been sought for 3 to 5 years tenure. While ONGC is seeking a price benchmarked to Brent crude oil, RIL-BP sold about 13 mmscmd of new gas from KG-D6 at a price linked to Platts JKM (Japan Korea marker) – the liquefied natural gas (LNG) benchmark price assessment for spot physical cargoes.
India’s natural gas consumption is projected to rise to as much as 550 mmscmd by the end of the decade from about 174 mmscmd now as the user base expands with the inclusion of newer industries such as steel, according to GAIL (India) Ltd. While the government is targeting to increase the share of natural gas in the primary energy basket to 15 percent by 2030 from the current 6.2 percent, the share of the environment-friendly fuel in the total energy demand is only 2 percent. Gas consumption presently is around 174 mmscmd, largely by fertilizer plants, city gas networks and power units. Of this, 49 percent is met by domestic production and the rest through imports in form of LNG. LNG will continue to play a leading role in meeting India’s gas requirements in spite of a strong and welcome upswing in domestic production. The indigenous production has already jumped around 19-20 mmscmd in the last quarter and LNG import capacity will rise to 40 million tonnes per annum (MTPA). According to Shell Energy India, India needs to look at LNG for transport the same way it is doing for electric vehicles. Bringing gas under GST (Goods and Services Tax) and reducing the cost of LNG-fuelled trucks can push the use of super-chilled fuel in transport.
RIL’s board decided to implement a ‘Scheme of Arrangement’ to transfer the ‘Gasification’ undertaking into a wholly-owned subsidiary (WOS). According to RIL, repurposing the ‘Gasification’ assets will help use ‘syngas’ as a reliable source of feedstock to produce these chemicals and cater to growing domestic demand, resulting in an attractive business opportunity. Furthermore, with optionality in applications for ‘Syngas’, the nature of risk and returns associated with the gasifier assets will likely be distinct from those of the other businesses of the company. The ‘Gasification’ project at Jamnagar was set up with the objective to produce syngas to meet the energy requirements as refinery off-gases, which earlier served as fuel, were repurposed into feedstock for the ‘Refinery Off Gas Cracker’ (ROGC). Besides, ‘Syngas’ as a fuel ensures reliability of supply and helps reduce volatility in the energy costs. The ‘Syngas’ is also used to produce Hydrogen for consumption in the Jamnagar refinery.
India’s H-Energy, a natural gas company, is seeking eight LNG cargoes a year for delivery over four years starting from April, 2022. The tender closes on 17 December. H-Energy was expected to commission its floating storage and regasification unit (FSRU) at Jaigarh port in Maharashtra this year, though the terminal, had already been delayed on several occasions. The company is also constructing LNG re-gasification terminals on India’s east coast at Kakinada, Andhra Pradesh and at Kukrahati, West Bengal.
The government has set up a committee to work out measures need to make natural gas available to power plants at “reasonably stable prices. India has 24,900 megawatt (MW) of gas-based power generation capacity. But of this, 14,305 MW is stranded due to the non-availability of reasonably priced gas. The average domestic gas supplied to gas-based power plants is just over 25 mmscmd, which is 70 percent short of the allocation or the requirement. While gas-based power plants act as balancers in the grid, making available gas to power plants is part of a larger plan to increase the share of environment-friendly fuel in India’s primary energy basket to 15 percent by 2030 from the current 6.7 percent. Natural gas as a fuel is convenient to use and can be easily transported through pipelines. It is cleaner than several other fossil fuels. Of the total gas consumption of about 60 billion cubic meters (bcm), more than half or 33 bcm was imported. In absence of sufficient domestic production, India imports gas in form of LNG. However, in recent weeks, LNG prices shot up to a record high of US$56 per million British thermal unit (mmBtu) in comparison to US$5-6 per mmBtu rates prevalent previously. The prices have gone down to US$30 but even this rate is extremely unaffordable. India has some long-term LNG supply contracts, which are indexed to different benchmarks, thereby giving it rates that are much lower than current international prices. As per the oil ministry, the focus is on exploring more areas to find gas reserves as well as raising output from existing fields, adding output is likely to rise next year on the back of major discoveries in the KG basin in the eastern offshore coming to production. The increase was mainly because of newer fields in the KG-D6 block of Reliance Industries Ltd being brought to production.
Norway’s petroleum output in October rose from the previous month, exceeding official forecasts, according to preliminary data from the Norwegian Petroleum Directorate (NPD). As per the NPD, crude oil output increased to 1.82 million barrels per day (bpd) in October from 1.77 million bpd in September, and compared to the official forecast of 1.77 million. Natural gas production in October also rose to 10.4 bcm from 8.9 bcm a month ago, above the forecast of 10.3 bcm.
US (United States) giant ExxonMobil and Qatar Energy signed a contract for oil and gas exploration and production-sharing off the divided island of Cyprus despite Turkey’s opposition to the deal. Cypriot Energy Ministry and Qatar Energy’s International Upstream and Exploration, signed the contract in Nicosia. It is the second gas exploration contract that the consortium has signed for Block 5 in the island’s Exclusive Economic Zone (EEZ). In February 2019, the consortium discovered a huge natural gas reserve off Cyprus in Block 10, the island’s largest find to date, holding an estimated five to 8 trillion cubic feet (TCF). The consortium plans to drill an appraisal well on Block 10 in late December, with results expected by the end of February. Oil and gas drilling off Cyprus has been interrupted by the Covid-19 pandemic. Turkey has threatened to prevent ExxonMobil’s search for oil and gas off Cyprus after Nicosia awarded it the rights to Block 5.
Saudi Aramco has signed a US$15.5 bn lease and leaseback agreement for its gas pipeline network with a consortium led by BlackRock Real Assets and Hassana Investment Company in its second major infrastructure deal this year. The deal signed underscores how Aramco — the kingdom’s cash cow — is seeking to monetise its once-untouchable assets to generate revenue for the Saudi government as it accelerates efforts to diversify the oil-reliant economy. In June, Aramco sold a 49 percent stake in its oil pipeline business to a consortium led by US-based EIG Global Energy Partners for US$12.4 bn. Under the new deal, a newly formed subsidiary, Aramco Gas Pipelines Company, will lease usage rights in Aramco’s gas pipeline network and lease them back to Aramco for a 20-year period, the Saudi oil firm said. In return, Aramco Gas Pipelines Company will receive a tariff payable by Aramco for the gas products that flow through the network, backed by minimum commitments on throughput.
US LNG company Cheniere Energy Inc’s marketing arm agreed to sell LNG to a unit of Chinese natural gas distribution company Foran Energy Group Co Ltd for 20 years starting in January 2023. As per some analysts, the deal should move Cheniere closer to making a final investment decision (FID) to build the proposed Stage 3 expansion at its Corpus Christi plant in Texas, which is expected in 2022. The deal is one of several announced in recent weeks as LNG buyers seek to lock in long-term prices and supplies of the super-cooled fuel as global energy shortages have boosted prices to record highs. Utilities around the world are competing for LNG cargoes to fill extremely low gas stockpiles in Europe ahead of the winter heating season and meet insatiable demand for the fuel in Asia where coal and gas shortages have caused power blackouts in China. Over the past couple of months, Cheniere has signed agreements to sell LNG to units of French energy company Engie SA, Anglo-Swiss mining and commodities trading firm Glencore PLC, Chinese gas distribution company ENN Natural Gas Co Ltd and chemical and fertilizer producer Sinochem.
Russian gas producer Novatek’s Arctic LNG 2 future plant has signed loan agreements with foreign and Russian banks worth €9.5 bn (US$10.8 bn), securing necessary external financing for the project. The producer said the Chinese financial institutions signed credit facility agreements totalling up to €2.5 bn (US$2.8 bn).
Australian environmental groups vowed to scupper plans for a vast new gas project off the country’s pristine northwest coast, saying it would critically undercut international climate efforts. Woodside Petroleum — fast becoming a major energy market player — finalised plans to sink US$12 bn into developing the remote Scarborough gas field, beginning exports by 2026. The country is already one of the world’s largest exporters of coal and gas, despite feeling the effects of climate change through worsening bushfires, droughts and flooding. Supporters argue that gas is less polluting than other fossil fuels and is a necessary bridge to a cleaner energy future.
16 December: Reliance Industries Ltd (RIL) aims to get the first cargo of oil from its new Abu Dhabi-based trading unit in December. The Indian conglomerate aims to get about a 500,000 barrels of cargo of United Arab Emirates’ Das crude from RINL. Abu Dhabi National Oil Co (ADNOC) supplied one million barrels of Das crude from the cavern to RIL in October and 2 million barrels in November, trade data shows
21 December: The Comptroller Auditor General of India (CAG) pulled up ONGC (Oil and Natural Gas Corporation) for flaring of high-pressure gas valued at INR8.16 bn in the Mumbai High Field during 2012-13 to 2019-20, due to the non-availability of standby process gas compressors, power shutdowns and frequent tripping of process gas compressors. The CAG said another public sector firm Indian Oil Corporation Ltd collected INR2.62 bn of turnover tax from consumers in Andhra Pradesh in violation of legal provisions of the Andhra Pradesh General Sales Tax Act, 1957. Regarding ONGC, CAG said high-pressure gas evolved in the process of separation of oil, water and gas in the offshore process system of the Mumbai High offshore fields is further compressed in the process gas compressors and fed to the wells for gas lift purpose. In this process, balance gas is transported to gas processing plant of ONGC at Uran for further processing and sale to consumers. Any disruption in compression leads to flaring of valuable high-pressure gas which also has an adverse impact on environment. The government auditor said that in order to maximise gas production, it is imperative that all equipment is maintained and run effectively so that there is no loss of production. Flaring of gas also has an adverse impact on environment as the emission of carbon dioxide leads to greenhouse gases and global warming.
20 December: Japan’s Osaka Gas Co said it has entered India’s urban gas distribution market by investing in the local unit of Singapore-based AGP International Holdings (AG&P) as part of its overseas expansion drive. Demand in India’s natural gas market is set to surge as the government wants to raise the share of the cleaner fuel in its energy mix to 15 percent by 2030 from the current 6 percent to combat climate change. Osaka Gas, Japan’s second-biggest city gas supplier, plans to invest up to US$120 million in the Indian unit of AG&P together with a state-private fund, Japan Overseas Infrastructure Investment Corporation for Transport & Urban Development (JOIN). The AG&P unit has exclusive gas sales rights for eight years for 12 geographic areas, and infrastructure licenses for 25 years in those places. Osaka Gas, which did not disclose how big a stake it would own in the unit, said India was a key growth market in Asia for the firm.
16 December: Cairn Oil and Gas announced that it will sell one lakh standard cubic meters per day (scmd) of natural gas to Assam Gas Company Ltd (AGCL) for distributing it in the state. The two companies have signed an agreement in Guwahati for the gas sale in presence of Assam Industries and Commerce Minister Chandra Mohan Patowary. AGCL managing director Gokul Chandra Swargiyari said that the association with the private oil company will improve energy access in Assam and boost the state’s many industries, particularly the big tea estates. The Assam government-controlled company is determined to connect more domestic and industrial consumers to its existing network and reduce dependence on traditional fuels to contain carbon footprint and ensure energy access in the state, Swargiyari said. Cairn is looking to double its gas production from the existing 1,700 million metric standard cubic meters (mmscm) of gas to 4,700 mmscm by 2026.
19 December: India’s coal import registered a decline of 26.8 percent to 15.75 million tonnes (mt) in October over the same month a year ago. The country had imported 21.50 mt of coal in October 2020, according to data compiled by mjunction services. However, coal import in October was up 6 percent as compared to 14.85 mt imported during September 2021, the data show. Of the total import in October 2021, non-coking coal was at 9.47 mt, against 14.46 mt imported in October last year. Coking coal import was at 4.05 mt, lower than 4.92 mt imported in October 2020.
20 December: Adani Transmission Limited (ATL) said it has completed the construction of one of the India’s longest intra-state transmission lines of 897 circuit km. The transmission line, set up by ATL subsidiary Ghatampur Transmission Ltd (GTL) will connect Ghatampur thermal power station in Kanpur district to Hapur substation in western Uttar Pradesh, the company said. The transmission line comprises four 765KV and 400KV bay extensions at Agra, Greater Noida and Hapur. This project has been developed under PPP mode on a build, own, operate and maintain (BOOM) basis. This will provide transmission services to long-term transmission customers (LTTC) with 35 years of runway ahead, the company said. The project will evacuate power from 3×660 MW Ghatampur TPS owned by the Neyveli Uttar Pradesh Power Limited — a joint venture between Neyveli Lignite Corporation and Uttar Pradesh Rajya Vidyut Utpadan Nigam — and will also strengthen UP’s transmission network. The transmission line passes through severe right of way (ROW) challenged urban areas and also through highly undulated ravine topography. One of the biggest challenges surpassed by GTL was the uncertainty caused by the COVID pandemic which made deployment of the workforce difficult.
18 December: Gujarat Alkalies and Chemicals Limited (GACL) and GAIL (India) Limited signed a Memorandum of Understanding (MoU) for setting up a bioethanol plant with a production capacity of 500 kilo litre per day (KLD) in Gujarat. Apart from the plant, both the companies also agreed to cooperate in other areas of mutual interest. The MoU was signed in the presence of Chief Minister Bhupendra Patel. The proposed plant will use corn/broken rice as feedstock with eco-friendly technology and it will produce 500 KLD bioethanol, which will be utilised for blending in petrol. With Dahod, Panchmahal, Aravalli and Mahisagar being the major corn-producing districts in Gujarat, the bioethanol plant is likely to come up in one of these districts. A detailed feasibility study through a third party is in progress for the project.
17 December: Noting that net zero targets are expected to be met through a combination of clean energy sources, including nuclear power, the government said that in this context, India’s present nuclear power capacity of 6,780 MW is planned to be increased to 22,480 MW by 2031. Minister of State in the Department of Space and Department of Atomic Energy Jitendra Singh said the present installed nuclear power capacity in the country is 6,780 MW and the share of nuclear power in the total electricity generation in the country is about 3.1 percent in the year 2020-21. He said the government has accorded administrative approval and financial sanction for 10 indigenous Pressurised Heavy Water Reactors (PHWRs) with an aggregate capacity of 7,000 MW to be set up in fleet mode.
17 December: France’s TotalEnergies, Royal Dutch Shell, Malaysia’s Petronas and Qatar Energy scooped up big offshore fields in Brazil together with Petrobras, paying nearly US$2 billion to its cash-strapped government. TotalEnergies, which snapped up a stake in both blocks, said the investment will bring output with “costs well below US$20 per barrel of oil equivalent” and with carbon emissions rates below industry levels. Brazil attempted to auction both fields in 2019, but neither received offers, even from Petrobras. At the time, complex legal issues and rich signing bonuses kept oil majors away. This time, the bidding terms were considered more attractive, several industry sources told Reuters, largely due to big cuts in both signing bonuses and minimum profit oil. Oil majors will be able to add production to their portfolios in the short term. Petrobras is ramping up production at Sepia to 180,000 barrels per day (bpd) and has reached the 160,000 bpd maximum capacity at Atapu. A second platform is planned for each field. Cementing Brazil’s status as Latin Americas biggest oil producer, the two fields could boost the country’s production by 12 percent over the next six years, adding 700,000 bpd, and bringing in almost US$40 billion in investment, its energy ministry said after the auction. Petrobras is set to receive US$6.2 billion for past investments in the two fields.
21 December: The United States (US) is set to become the world’s biggest liquefied natural gas (LNG) exporter in 2022, surpassing Qatar and Australia, and may hold that title for years to come. In a year when China and other large economies in Europe and Asia scrambled to source enough supply for heating and power generation, the US was sitting on a bevy of supply – one that will grow in coming years. Global LNG demand has hit record highs each year since 2015, due mostly to surging demand in China and the rest of Asia. Much of that global appetite has been met by steadily rising US LNG exports, which have reached new records every year since 2016 and is poised to continue in 2022. The US Energy Information Administration projects US LNG exports will reach 11.5 billion cubic feet per day (bcfd) in 2022. That would account for roughly 22 percent of expected world LNG demand of 53.3 bcfd next year, according to analysts at Goldman Sachs and would outpace both Australia and Qatar, the two largest exporters at present. One billion cubic feet is enough gas for about 5 million US homes for a day. The US should remain the biggest LNG exporter by capacity until around 2025, when Qatar could regain the lead as its North Field expansion starts to enter service. Major US developers like Cheniere Energy, the largest US exporter, have signed numerous long-term deals to sell LNG in recent months that should enable them to secure the financing needed to go forward with additional multibillion-dollar projects. The US is expected to become the largest exporter of liquefied natural gas (LNG) by 2022, surpassing Australia and Qatar. Many of those long-term contracts came from Chinese buyers. So far in 2021, most US LNG exports went to Asia with about 13 percent going to South Korea, 13 percent to China and 10 percent to Japan, according to US energy data. Those were the same top three destinations in 2020 when 13 percent of US LNG went to South Korea, 12 percent to Japan and 9 percent to China. Gas prices around the world repeatedly reached record highs in 2021 as utilities tried to lock in LNG cargoes to rebuild low stockpiles in Europe and meet heavy demand in Asia.
21 December: European gas prices hit a new record high after a pipeline that brings Russian gas to Germany switched to flow east, a move the Kremlin said had no political implications, while two big German customers said Gazprom was meeting supply obligations. Westward gas flows through the Yamal-Europe pipeline, one of the major routes for Russian gas to Europe, had been falling and, after stopping early, reversed direction, data from network operator Gascade showed. Some western politicians and industry experts have accused Russia of withholding gas deliveries to Europe amid political tensions over Ukraine, as well as delays in the certification of another pipeline, Nord Stream 2. The front-month wholesale Dutch gas price, the European benchmark, rose more than 16% to a record high of 171.40 euros (US$193.46) per megawatt hour, and the equivalent British gas contract also hit a new peak at 4.29 pounds (US$5.68) per therm.
21 December: Egypt’s Suez Canal will reduce rebates on canal tolls for liquefied natural gas carriers from 1 January till 30 June, the canal authority said. The rebates to LNG tankers operating between the American Gulf, ports South of the American Gulf, and the Gulf and ports at west of India till Kochi port will have a rebate of 30 percent of Suez Canal normal tolls, while eastern ports to Kochi port up to Singapore will have a rebate of 55 percent, and Singapore ports and its eastern ports will have a rebate of 70 percent.
19 December: As part of increasing business collaboration and strengthening ties with Vietnam, Essar Exploration and Production, the exploration arm of Essar Group, said it is committed to fast-track the development process of the Ken-Bau basin in Vietnam. Essar Exploration and Production is an emerging player in natural gas exploration and production worldwide. It and Ente Nazionale Idrocarburi have a significant investment in Block 114, located in the offshore area of central Vietnam.
16 December: The World Bank has urged Indonesia to drop a policy forcing miners to supply a set amount of subsidised coal to its state power company, which it said has encouraged the use of the dirty fuel in electricity generation. The Southeast Asian country is the biggest exporter of thermal coal globally and among the top ten greenhouse gas emitters. Indonesia has a so-called Domestic Market Obligation (DMO) policy whereby coal miners must supply 25 percent of annual production to state utility Perusahaan Listrik Negara (PLN), at a maximum price of US$70 per tonne, well below current market prices. The policy has effectively subsidised coal-fired power plants, the bank said.
15 December: China’s coal output hit a record high in November as Beijing urged miners to ramp up production to ensure sufficient energy supplies in the winter heating season. China, the world’s biggest coal miner and consumer, produced 370.84 million tonnes (mt) of the dirty fossil fuel last month, data from the National Bureau of Statistics showed. That compares to a previous record of 357.09 mt set in October and was up 4.6 percent from the same period last year. For the first 11 months of 2021, output reached 3.67 billion tonnes, up 4.2 percent on last year.
17 December: The organization responsible for North American electric reliability said that several parts of the United States (US) could face energy shortfalls during the next decade due to insufficient power generation resources. Specifically, the North American Electric Reliability Corp (NERC) said in a study that there is a high probability of insufficient resources and energy to serve electricity demand as early as summer 2022 in many parts of the Western Interconnection, which includes California and other states in the US West. Extreme weather conditions and performance issues associated with some inverter-based resources, such as solar, wind and new battery or hybrid generation, may also have a potential negative impact on reliability, NERC said.
20 December: Rolls-Royce said Qatar’s sovereign wealth fund would invest 85 million pounds (US$112.12 million) in the British company’s new low-carbon nuclear power business in exchange for a 10 percent equity stake. The London-listed firm has agreed with the Qatar Investment Authority for the funding in its Small Modular Reactors business, which Rolls-Royce said was now fully funded having secured 490 million pounds through commercial equities and grants. Qatar and Rolls-Royce said last month that they would team up in a multi-billion pound project to develop and invest in green technology start-ups in the UK and the Gulf Arab state.
20 December: Brazil’s state-run oil company Petrobras will start testing new renewable diesel based on co-processed edible oils with customers in January, while awaiting regulatory approval to sell it commercially, the company said. The tests are expected to take about six months and will be backed by a fuel distributor and a bus fleet owner, whose names are yet to be revealed, the company said. The oil giant had successfully tested the renewable diesel production system at its Repar refinery in mid-2020, but it sees the new testing phase as important in confirming its effectiveness. Repar is currently capable of producing 114,000 tonnes per year of renewable fuel based on co-processed soybean oil. The move is part of Petrobras’ plan to insert renewable fuels based on new technologies into Brazil’s market. The investments include adapting the Paulinia and Cubatao refineries so that both could produce a total of 505,000 tonnes of renewable fuel per year. Most of the money, however, would go toward building a 100 percent renewable biorefinery capable of producing 500,000 to 800,000 tonnes per year, which is expected to start operating in 2027 in a location yet to be determined, the company said.
16 December: Goldman Sachs Group Inc said it would work with clients in three areas to reduce carbon emissions substantially by 2030, as it revealed new details about its approach to countering climate change in a report. The bank said it would initially focus on oil and gas, power and auto manufacturing, aiming to reduce emissions in those high-emissions sectors by 2030. Starting with a baseline of 2019 levels, it said it would help oil and gas clients reduce emissions by 17-22 percent, power by 48-65 percent and autos by 49-54 percent. Goldman said it would consider the use of carbon credits when it can verify that they are of high quality to achieve those goals. Other banks including JPMorgan Chase & Co and Morgan Stanley have set similar targets. The targets are a sign of how banks are ramping up pressure on clients to reduce emissions as the industry comes under increasing pressure globally to cut off financing for industries such as coal that harm the environment.
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