Rajasthan CM Approves Draft Of Green Hydrogen Policy
The state government has announced “Rajasthan Green Hydrogen Policy-2023”, keeping in view clean energy production, future energy needs, and climate change. Chief minister Ashok Gehlot has approved the policy draft and the notification will be issued soon by the energy department, said a government statement on Saturday. Under this policy, companies producing green energy in the state will get various types of incentives. Green hydrogen is produced by electrolysis of water using renewable energy. The main use of green hydrogen is in refinery, steel plants, and manufacture of ammonia. The state government will provide various facilities to investors under the policy. These include 50 per cent rebate in transmission and distribution charges for 10 years for 500 KTPA (kilo-tonnes per annum) renewable energy plants to be installed on the state’s transmission system. The state government has set a target of 2000 KTPA energy production by the year 2030 in the policy.
India raises windfall tax on petroleum crude to Rs 10,000/tonne
India’s government has increased the windfall tax on petroleum crude to Rs 10,000 per tonne from 6,700 rupees per tonne, according to a government notification on Friday. The increase will come into effect from Sept. 16. The government has cut the windfall tax on aviation turbine fuel to 3.50 rupees per litre from 4 rupees per litre.
Gas migration case: What exactly is the dispute between Reliance and ONGC?
A division bench of the Delhi High Court on Thursday sought a response from Reliance Industries Ltd. (RIL) and its partners on the government’s appeal that accused the Mukesh Ambani-owned conglomerate and its partners of committing an “insidious fraud” and “unjust enrichment of over $1.729 billion” by siphoning gas from deposits they had no right to exploit. The dispute over the gas migrating from ONGC’s block to the adjacent block of RIL and its partners dates back to 2014, and has been through several judicial and arbitration processes. How it all started In 2014, state-run ONGC approached the court, complaining that gas from its blocks was being produced by RIL. ONGC claimed that RIL had deliberately drilled wells close to the common boundary of the blocks and that some gas it pumped out was from its adjoining block. RIL is the operator of the said KG-D6 block with 60 per cent interest while BP holds 30 per cent. The remaining 10 per cent is with Niko Resources. ONGC claims that RIL has benefited from gas flow between their adjacent fields during the 2009-2013 period and took RIL to court over the matter. RIL maintained that it had followed the Production Sharing Contract in letter and spirit and done no wrong. It has drilled all wells within its boundary walls. The two companies appointed US-based consulting agency DeGolyer and MacNaughton (D&M), to examine the issue. D&M said that natural gas worth over Rs 11,000 crore had migrated from idling KG fields of the state-owned firm to the adjoining KG-D6 block of RIL. The Justice Shah committee report After the consultant’s report, a committee was set up under Justice A.P. Shah in 2015 to quantify unfair enrichment, if any, by RIL and to recommend ways to compensate ONGC and the government. The Justice Shah Committee opined that RIL should pay the government for the natural gas it has drawn from an adjacent block of ONGC in the KG basin of the Bay of Bengal in the past seven years. The arbitration panel rejects govt contention The Oil Ministry in November 2015 issued a notice to RIL, Niko and UK’s BP Plc seeking $1.47 billion for producing in the seven years ended March 31, 2016 about 338.332 million British thermal units of gas that had seeped or migrated from the state-owned ONGC blocks into their adjoining KG-D6 in the Bay of Bengal. After deducting $71.71 million royalty paid on the gas produced and adding an interest at the rate of Libor plus 2 per cent, totalling $149.86 million, a total demand of $1.55 billion was made on RIL, BP and Niko. In 2016, RIL-BP-Niko sent an arbitration notice, thereby showing intent of quickly resolving the sticky issue. Next year, a three- member arbitration panel was set up to judge the validity of the government’s demand of $1.55 billion compensation from Reliance Industries for “unfairly” producing ONGC’s gas. Favouring RIL-led consortium in the so-called gas migration dispute case, the three-member tribunal headed by Singapore-based arbitrator Lawrence Boo in its 2:1 award in 2018 rejected the government’s contention. It said that the production sharing contract (PSC) doesn’t prohibit the contractor from producing gas—irrespective of its source—as long as the producing wells were located inside the contract area. It also had held that the consortium was not liable to pay any amount to the government and had also directed the latter to pay $8.3 million as the cost of arbitration to the consortium. The government moves court Soon after, the government moved the court, seeking setting aside of the arbitration award on the grounds that “the award strikes at the heart of the public policy and has given a premium to a contractor (RIL) that has amassed vast wealth by committing an insidious fraud as well as criminal offence …” “The unjust enrichment amassed by the contractor had already reached more than $1.729 billion today (at the time of filing petition), and is since increasing as the production of migrated gas is still continuing,” it had stated in its petition. On Thursday, September 14, Delhi High Court’s division bench sought a response from Reliance Industries and others on the government’s appeal. Attorney General R Venkentaramani and former AG KK Venugopal, appearing for the government, argued that RIL in 2003 knew about the connectivity of its block with that of the adjoining ONGC block. They also accused RIL of ‘consciously and deliberately’ extracting and selling the adjoining ONGC gas without the government’s knowledge. The senior lawyers also argued that RIL had earlier taken a categorical stand that “there is no connectivity and continuity” between RIL’s and ONGC’s block. And the impugned arbitral award is in conflict with the public policy of India, they added. RIL through counsel Sameer Parekh opposed the government’s appeal, arguing that these issues cannot be reopened under Section 37 of the Arb Act. Public trust doctrine and other points raised by the govt have been looked into both by the arbitral tribunal as well as the single judge. Citing the director general of hydrocarbons report, the lawyer argued that the study of migration of gas could have been done by the ministry in 2009 itself, much before the gas block was given to RIL, but the ministry chose not to do so. The adjoining ONGC gas block was underdeveloped when RIL started extracting gas and it would have been “infeasible” to extract gas from the ONGC’s block which was at a different stage of development then, it said.
Air Fares Poised To Skyrocket As EU Adopts Green Fuels For Aviation
Back in 2008, Virgin Atlantic made history after flying a Boeing 747 between London and Amsterdam partly powered by a biofuel made from Brazilian babassu nuts and coconuts. Although Virgin Atlantic founder Sir Richard Branson hailed the event as a “vital breakthrough”, many people dismissed it as just another one of his marketing stunts. And they were right. In November 2023, Virgin Atlantic will operate the world’s first transatlantic flight powered entirely by green aviation fuels in yet another one-off demo. A decade and a half since Virgin Atlantic’s 2008 demo, only five airports have regular biofuel distribution today (Bergen, Brisbane, Los Angeles, Oslo and Stockholm). On a global level, aviation biofuels account for less than 1% of the 1.5 billion barrels of aviation fuels, or ~15% of global oil supply, that commercial airlines burn through in a typical year. Indeed, the global aviation industry is a leading polluter; it would rank among the top 10 emitters if it were a country. But this is about to change in Europe. On Wednesday, EU lawmakers approved new rules that require at least 2% of jet fuel used by airlines to be sustainable as of 2025, with that share to increase every five years to hit 70% by 2050. The new legislation is part of the EU ’s “Fit for 55” package, which has set a goal to cut greenhouse gas emissions by least 55% by 2030. Whereas 2% might not seem like much, consider that currently less than 0.05% of Europe’s aviation fuel is sustainable, meaning airlines within the bloc will have to increase their share of clean fuels by more than 40x in the space of just two years. For a sustainable aviation fuel (SAF) to qualify as sustainable, it must be able to cut greenhouse gas emissions by at least 50% compared to conventional fossil fuel-based jet fuels. At the top of the sustainability hierarchy are fuels made from biomass including crop residues, animal waste, forestry residue, algae and even everyday rubbish, such as product packaging and food leftovers that can typically lower CO2 emissions by 85-95%. But achieving cleaner flights will not come cheap. SAF are significantly more expensive than conventional jet fuel, and this cost premium is the key barrier to their wider adoption. Fuel costs constitute the biggest line item for airlines, typically accounting for ~22% of their overheads. Using renewable air fuel would likely necessitate passing the extra costs to customers by increasing ticket prices, something that would not work well unless everybody did it at once because airline-specific fare changes are highly price elastic. The economics of some SAF are just egregious: earlier in the year, Exxon Mobil (NYSE:XOM) pulled the plug on its 14-year-long algae biofuels project because it found that crude would have to hit ~$500/bbl for algae biofuels to compete successfully. Either way, air travel is about to get a lot more expensive, so much so that the “demand reduction impact” that would result from people being priced out is expected to account for ~14% of the required cuts to hit the EU emissions target. Bright Future For Synthetic Fuels The latest move by the EU improves the outlook for synthetic fuels even further. Synthetic fuels are liquid fuels produced from natural gas, coal, peat, and oil shale, and include synthetic diesel, synthetic kerosene and green methanol. According to the IEA, synthetic fuels are vital in the decarbonization of transport and industry by 2050. Carbon-neutral synthetic fuels are manufactured using captured carbon dioxide or carbon monoxide from the atmosphere or an industrial process such as steel making and also from biomass that is gasified before being catalyzed with hydrogen using thermal or chemical means. German multinational engineering and technology company BOSCH is a leading advocate of synthetic fuels. According to the company, synthetic fuels will help the roughly half of the current fleet of vehicles expected to still be on the roads by 2030 to play a part in cutting CO2 emissions (synthetic fuels are 100% compatible with current fossil fuel engines). Synthetic fuels can also be blended in fossil fuels or can completely replace them in existing ships, airplanes or industrial technologies. Studies have found that sustainable aviation fuels including synthetic or bio-based jet fuels, are so far the most promising option for the decarbonization of the carbon-heavy aviation sector. Two years ago, the Netherlands demo’ed the first passenger flight powered by synthetic fuels with an energy density only marginally lower than that of fossil-based kerosene. The IEA has predicted that by 2030, 15% of total fuel consumption in aviation will be SAF, rising to 75% by 2050.
The 5 South American Countries With The Largest Natural Gas Reserves
South America is fast emerging, once again, as one of the world’s hottest drilling locations, with the continent believed to contain considerable volumes of commercially extractable natural gas. While offshore Guyana is garnering the lion’s share of attention from foreign energy companies, it isn’t the only country in South America benefiting from significant hydrocarbon wealth. Argentina, despite its economic woes, is profiting from a massive unconventional hydrocarbon boom that could see the country emerge as a regional natural gas hub, while production from Brazil’s offshore oil fields is growing at a steady clip. These events are challenging South America’s traditional energy dynamics, with Venezuela, Colombia and Bolivia no longer the continent’s leading hydrocarbon producers. Here are South America’s five leading countries by proven natural gas reserves. #5 Peru The troubled Andean country of Peru, which is locked in a lengthy political crisis, possesses the fifth-largest proven natural gas reserves in South America. Those reserves, at the end of 2022, totaled 8.4 trillion cubic feet, which is 19% less than a year earlier and nearly half of the 15.4 trillion cubic feet reported a decade earlier. During August 2022, Peru pumped an average of 1.27 billion cubic feet of natural gas per day, which was 2% higher than a month earlier and a notable 16% greater than the same period during 2022. Those numbers demonstrate Peru is successfully scaling up natural gas output in response to growing domestic energy demand but needs to attract greater investment in hydrocarbon exploration and development to boost reserves. Peru’s hydrocarbon sector has been roiled by crisis and conflict for many years. Frequent anti-government and oil industry protests in Peru’s remote Amazon region have forced the shuttering of oilfields and Peru’s northern pipeline, which connects those fields to the Pacific Coast. Those protests are triggered by the immense environmental damage caused by oil industry operations and the lack of spending by the government in Lima on crucial infrastructure in Peru’s Amazon. This is weighing on Lima’s efforts to attract crucial foreign energy investment needed to boost proven reserves and production. #4 Bolivia Once known as the beating heart of South America’s natural gas industry, Bolivia’s fossil fuel fortunes are fading. It is estimated that the landlocked Andean country has proven natural gas reserves of nearly 9 trillion cubic feet, down from 11 trillion cubic feet a decade ago. That isn’t the only sign of an industry in decline. For June 2023, Bolivia pumped 1.25 billion cubic feet of natural gas per day, which, despite being 3% greater than a month prior, was a worrying 15% lower year over year. Natural gas production has plunged sharply in recent years, with 2022 output of 1.400 billion cubic feet per day 11% lower than 2021 and considerably less than the 1.85 billion cubic feet per day extracted a decade earlier. For these reasons, there is growing uncertainty regarding the future of Bolivia’s hydrocarbon sector, which was once responsible for keeping the lights on in neighboring Argentina. Indeed, Bolivia’s natural gas production has been steadily declining since 2015 and is expected to plunge well below one billion cubic feet per day in coming years due to aging mature gas fields, a lack of discoveries and a dearth of industry investment. Industry analysts believe that the end of the country’s once-mighty natural gas industry is close, with natural gas output expected to decline calamitously over the near-term. According to industry consultancy Wood Mackenzie, Bolivia’s natural gas production could fall to as low as 400 million cubic feet per day by the end of this decade. #3 Argentina In a surprising development, Argentina, which recently avoided yet another sovereign debt default and is struggling with triple-digit inflation, now has the fourth-largest proven natural gas reserves in Latin America. At the end of 2022, data from the Ministry of Economy showed that proven natural gas reserves totaled 15.4 trillion cubic feet, which is not only an 11% increase over a year earlier but a stunning three times greater than a decade earlier. That incredible growth can be attributed to the ongoing exploitation of the Vaca Muerta shale formation, which didn’t start in earnest until 2013 after the government of Cristina de Kirchner nationalized Repsol-owned YPF. The ongoing exploitation of the Vaca Muerta saw Argentina’s natural gas production surge to an all-time high of nearly 5 billion cubic feet per day during August 2022. While output has declined since then, Argentina still lifted an average of 4.9 billion cubic feet for August 2023. Production will keep growing with YPF budgeting investment of $2.3 billion for its shale operations during 2023 with a view to boosting natural gas production by 15% compared to 2022. The Vaca Muerta, with an estimated 16 billion barrels of oil and 308 trillion cubic feet of natural gas, is believed to contain the second-largest shale gas reserves in the world. The ongoing development of the geological formation, which has been compared to the prolific Eagle Ford shale in Southern Texas, will see Argentina emerge as a major hydrocarbon producer and exporter in Latin America. This will allow Argentina to dial down energy imports, especially natural gas from neighboring Bolivia, which will go a long way to reducing a massive trade deficit and repairing a broken economy. #2 Brazil South America’s largest oil producer, Brazil, also possesses the second-largest natural gas reserves on the continent, which total 14.4 trillion cubic feet. Most of those reserves are contained within Brazil’s prolific offshore pre-salt fields and are associated with oil production. During July 2023, Brazil’s hydrocarbon output soared to a record high of 4.48 million barrels of oil equivalent, 78% weighted to oil, which was 3.6% greater than a month earlier and a whopping 17.5% higher year over year. Natural gas output for the month hit an all-time high of 5.4 billion cubic feet per day, which was 1.2% higher month over month and a notable 13.6% greater than a year earlier. Natural gas production in Latin America’s largest economy will continue
Indian oil firms explore using stranded $600 million to buy Russian oil
Indian oil companies are exploring the possibility of using close to $600 million of their dividend income stranded in Russia to buy oil from that country, officials said on Thursday. India’s top four oil companies — Indian Oil Corporation (IOC), a unit of Bharat Petroleum Corporation Ltd, Oil India Ltd and ONGC Videsh Ltd — haven’t been able to repatriate dividend income they accrue from their investments in Russian oil and gas fields. That money is lying in their bank accounts in Russia but could not be brought to India due to tough Western sanctions that followed Moscow’s invasion of Ukraine. This is at a time when Russia has emerged as the top crude oil supplier to India, accounting for more than a third of all purchases New Delhi makes from overseas. Officials said one of the options could be to loan the money lying in Russian bank accounts to entities buying oil. These entities could repay the loan in India. The entities that buy oil from Russia include IOC and BPCL. “We are studying legal and financial implications of such a move,” an official said. “We are mindful of the sanctions and do not want to do anything that may in any way attract any breach.” Indian state oil firms have invested USD 5.46 billion in buying stakes in four different assets in Russia. These include a 49.9 per cent stake in the Vankorneft oil and gas field and another 29.9 per cent in the TAAS-Yuryakh Neftegazodobycha fields. They get dividends on profits made by the operating consortium from selling oil and gas produced from the fields. Soon after Russia’s invasion of Ukraine in February last year, several major Russian banks were banned from the Society for Worldwide Interbank Financial Telecommunication (SWIFT) financial transaction processing system, constricting Moscow’s ability to access the global payments system. Also, the Russian government has put restrictions on the repatriation of dollars from that country to check volatility in foreign exchange rates. This led to a situation of dividend money getting stranded in Russia. ONGC Videsh Ltd (OVL), the overseas arm of state-owned Oil and Natural Gas Corporation (ONGC), holds a 26 per cent stake in Suzunskoye, Tagulskoye and Lodochnoye fields — collectively known as the Vankor cluster in the north-eastern part of the West Siberia. Indian Oil Corp (IOC), Oil India Ltd (OIL) and Bharat PetroResources Ltd (a unit of Bharat Petroleum Corp Ltd or BPCL) hold another 23.9 per cent in the same project. Russia’s Rosneft is the operator with 50.1 per cent interest. The consortium of OIL, IOC and Bharat PetroResources has a 29.9 per cent stake in TAAS-Yuryakh Neftegazodobycha. Separately, OIL chairman and managing director Ranjit Rath said about USD 150 million of dividend income of OIL is lying in bank accounts in Russia. The total for its consortium (IOC and BPRL included) is about USD 450 million, he said. OVL has another USD 130 million of dividend income. “We see this has a temporary phenomenon,” Rath said. “We are working at three levels — exploring legal options, analysing banking challenges and using government-to-government to negotiations.” He, however, refused to elaborate. Other officials said the options being explored includes using the stranded money to buy oil. “IOC as well as BPCL already are big buyers of Russian oil and perhaps they can use that money to buy oil,” an official said. “Legal and financial issues in doing so are currently being studied.” Another official said a solution is likely to emerge in 2-3 months’ time. The dividend is lying with the Commercial Indo Bank LLC (CIBL), which was a joint venture of the State Bank of India and Canara Bank. Canara Bank in March sold its 40 per cent stake in CIBL to SBI. The dividend from TAAS was paid on a quarterly basis, while Vankorneft’s earnings were paid half-yearly. The Indian firms are looking at options of how to repatriate the money from Russia, Rath said. All dividend income prior to the Ukraine war was repatriated but the one that accrued after that is stuck. The operations of the fields have not been impacted and they continue to produce as normal, he added. OVL also has a 20 per cent stake in the Sakhalin-1 oil and gas field in Far East Russia, and in 2009 acquired Imperial Energy, which has fields in Siberia, for USD 2.1 billion.
Why Oil Could Top $100 In Q4 2023
Oil prices have soared to a 10-month high on Wednesday, with a surprise build in U.S. crude inventories failing to dampen expectations of tight supplies for the rest of the year. Front-month November Brent crude closed +1.5% at $92.06/bbl, its best settlement since November 16 while U.S. front-month Nymex crude for October delivery settled +1.8% to $88.84/bbl, its highest closing price since November 11, 2022. WTI and Brent have now gained 10.7% and 7.1% YTD, respectively. The latest weekly data by the International Energy Agency (IEA) showed that U.S. crude inventories rose by 4 million barrels to 420.6 million barrels, a large increase compared to expectations by a Reuters poll for a 1.9 million-barrel drop. The Paris-based energy watchdog has revised down its demand growth forecast by 600,000 bpd. But that setback has failed to persuade the bulls to cross the aisle. “The big picture is the extended voluntary production cuts by Saudi Arabia and Russia. The deficit is now broadly equal to the Saudi additional voluntary cut,” Andrew Lipow, president of Lipow Oil Associates in Houston, told Reuters. The two countries have extended production cuts of 1.3 million barrels per day (bpd) of crude to year end, which Bank of America has predicted will lift Brent futures above the $100 a barrel threshold before the end of the year. The OPEC Secretariat Oil Market Report published on 12 September contained few significant changes, with the demand growth forecasts unchanged at 2.44 mb/d in 2023 and 2.45 mb/d in 2024 while non-OPEC supply growth was revised higher by 69 thousand barrels per day (kb/d) to 1.58 mb/d in 2023 and revised 6 kb/d lower to 1.38 mb/d in 2024. Commodity analysts at Standard Chartered remain firmly in the bull camp. The analysts have noted that oil prices have been driven higher in Q3 by sharp falls in inventories caused by excess demand, and have predicted that dynamic will continue in Q4. According to StanChart’s demand model, global crude inventories rose by 203 million barrels (mb) in H2-2022 but have forecast a 180 turn from that trend with global inventories expected to fall by 313 mb in H2-2023. The analysts have also predicted draws will average 1.4 mb/d in Q4, lower than Q3’s 2.0 mb/d average and August’s peak 3.1 mb/d draw, representing a significant additional tightening from a base of already low inventories. Meanwhile, the experts have forecast that China’s demand growth will continue being relatively slow and that U.S. supply growth will be relatively fast. Overall, they see a sizable net tightening remaining, reinforced in large part by a considerable y/y reduction in OPEC supply. And, now to the part that really matters: StanChart has forecast Brent prices in Q4 2023 to average USD 93/barrel (bbl), a prediction that has remained virtually unchanged for the past 15 months despite Brent trading across a wide USD 50/bbl range during that period. That said, the analysts have cautioned that their forecast is a period average rather than a point forecast and hence have not ruled out an intra-Q4 high above USD 100/bbl. Indeed, they are confident that oil prices are more likely than not to surprise to the upside. Hedge Funds Turn Ultra-Bullish Just three months ago, oil markets were extremely bearish and rife with short-sellers, thanks to an abundance of negative catalysts including elevated inventory levels, rising supplies by Russia, Iran and Venezuela, weak global demand and sub-par recovery by the Chinese economy. Indeed, StanChart revealed that speculative short volumes were at one point more than six times larger than those after the collapse of Lehman Brothers and Bear Stearns in 2008. But market sentiment has now improved quite dramatically, with hedge funds rushing back into the oil market with their most bullish wagers in more than a year after the extension of cuts by Saudi Arabia and Russia have sent crude surging 30 per cent since mid-June. In fact, the latest data showing positioning by money managers has revealed that they are at the most bullish on U.S. crude since June 2022. “A considerable amount of dry powder had been sitting on the sidelines, meaning the recent strong tape could set off a further chase and catch-up in positioning. This oil market has evolved into as much of a momentum-based market as it is a fundamentally based one,” Michael Tran, a global energy strategist at RBC Capital Markets, has told Bloomberg.
China’s LNG Buying Spree Threatens Global Gas Market Stability
China is back on the spot LNG market to seek cargoes for the coming winter, potentially upsetting a fragile balance in the global natural gas market just as Europe has reached its gas storage target well ahead of the November 1 deadline. Following a record slump in Chinese gas demand and LNG imports last year prompted by Covid-related lockdowns, China’s gas consumption has risen so far this year compared to 2022, although it’s still below the growth seen up to 2021. In recent months, China has signed a lot of long-term LNG supply deals, including with the top exporters, the United States and Qatar. But China is also back on the spot market with a massive tender for cargoes to be delivered later this year and throughout 2024. Intensified competition from China and other Asian buyers could leave Europe in an even more vulnerable position regarding supply for the 2023/2024 winter by driving prices higher and attracting more LNG cargoes to Asia than EU buyers would have liked. China’s state-owned energy giant Sinopec, via its trading arm Unipec, has recently issued a tender seeking to buy as many as 25 LNG cargoes between October 2023 and December 2024, trading sources familiar with the plans told Reuters this week. Sinopec is looking for offers to buy one LNG cargo for delivery in October, five cargoes for November, and seven for December 2023. The rest of the 25 cargoes will be delivered one each month in 2024, according to Reuters’ sources. Sinopec’s trading arm may have plans to resell all or some of those cargoes later and not use them for China’s domestic gas consumption. Whatever the case may be, that’s the biggest tender by a state-held Chinese buyer to seek LNG cargoes on the spot market since February this year, Bloomberg notes. Lockdowns and slower economic growth led last year to the first annual drop in China’s gas consumption since 1990, while China’s LNG imports slumped by 20%, mainly due to reduced demand and high LNG spot prices. This year, Chinese gas demand increased by 5% year-on-year in the first half of 2023, thanks to higher demand in the power and industrial sectors, Miaoru Huang, Research Director, Asia Pacific Gas and LNG, at Wood Mackenzie, wrote in a note earlier this month. China’s domestic gas production is growing, and pipeline supply from Russia to China is also on the rise. But LNG net imports into China in the first half of 2023 also rose, by 6% year-over-year, Huang noted. Going forward, “China will seek more influence on LNG pricing, and on the back of improving flexibility in its gas value chain, it could increasingly act as a swing market in the global LNG supply-demand balance,” Huang says. China’s ‘swing market’ role could be tested as early as this winter, especially if winter in Europe and/or Asia is colder than usual. “We go into this winter with Europe being fairly high-stocked,” Colin Parfitt, vice president of Midstream for Chevron, said at the Gastech 2023 conference in Singapore last week. However, Parfitt warned about possible high volatility if winter is colder. “My view is we’re not out of the woods yet, and we may not be out of the woods for a couple of years until this new supply comes up,” Parfitt said, as carried by Reuters. Despite high levels of gas stocks and reduced gas consumption and imports, Europe’s biggest economy, Germany, is not out of the woods in terms of gas shortages, German industry and government have been warning for months. The supply situation on the global LNG market could further worsen just ahead of the heating season with the ongoing dispute between Chevron and trade unions over pay and work conditions at two export facilities in Australia, which collectively account for 5% of global LNG supply.
India, Saudi Arabia to expedite IOC refinery plan
India and Saudi Arabia have agreed to accelerate Indian state-controlled refiner IOC’s 1.2mn b/d West Coast Refinery project. India and Saudi Arabia issued a joint statement during the visit of Saudi crown prince Mohammad bin Salman to India last week, following his meeting with Indian prime minister Narendra Modi. The deal was followed by the first meeting of the India-Saudi Arabia Strategic Partnership Council. “Both the prime minister and the crown prince extended their full support to the early implementation of the West Coast Refinery project, for which funds to the tune of $50bn are already earmarked,” ministry of external affairs secretary Ausaf Sayeed said in a press briefing on 11 September. IOC’s plans for a 1.2mn b/d refinery at Ratnagiri in west India’s Maharashtra state remain complicated by land acquisition problems. State-controlled Saudi Aramco and Abu Dhabi’s state-owned Adnoc are partners in the project. The two sides also agreed to set up a joint task force to help in identifying and channelling $100bn of investment from Saudi Arabia and for a monitoring committee to ensure progress on the refinery project, Sayeed added. Further details of the agreement, such as the timelines, were unavailable. The two sides also agreed to develop joint projects to transform oil into petrochemicals in the two countries but did not add further details. The joint statement included a number of discussed issues, including an initial agreement on 10 September to co-operate on several new energy and fossil fuel-related sectors. India and Saudi Arabia agreed to diversify their hydrocarbon trade into a comprehensive energy partnership, Sayeed said. The two countries will co-operate in the areas of renewable energy, energy efficiency, hydrogen, carbon capture, utilisation and storage and electricity grid interconnection, according to the Indian government. The two countries will also work together on oil, natural gas, a strategic petroleum reserve (SPR) and energy security. Several major global oil and commodity trading firms have expressed interest in building India’s new SPR, the government told the lower house of parliament on 3 August. The government has earmarked 50bn rupees ($600mn) in its budget for the April 2023-March 2024 fiscal year to rebuild the country’s SPR. The collaboration, for which a timeline is not yet available, will also involve qualitative partnerships between India and Saudi Arabia to localise materials, products and services related to all energy sectors, supply chains and technology, the government said without providing further details. Leaders of the US, India, Saudi Arabia, the UAE and the EU also agreed at the G20 Leaders’ Summit held in Delhi across 9-10 September to work together to establish a multinational rail and shipping corridor connecting south Asia to the Middle East and Europe. A possible timeline for the project was unavailable.
PESB picks Alok Sharma for Indian Oil’s Director (R&D) post
Alok Sharma is set to be next Director (Research & Development) of Indian Oil Corporation Limited (IOCL), a Maharatna oil marketing PSU under the Ministry of Petroleum & Natural Gas (MoPNG). He has been recommended for the post by the Public Enterprises Selection Board Panel (PESB) on Tuesday. Presently, he is serving as Executive Director (R&D) of the same organisation. Sharma has been recommended for the post of Director (R&D) of Indian Oil from a list of eight candidates, who were interviewed by the PESB selection panel. Out of eight candidates seven candidates were from Indian Oil and one candidate was from Bharat Petroleum Corporation Limited (BPCL).