Indian Oil signs long term LNG import deals with ADNOC LNG, TotalEnergies
Indian Oil Corp, the country’s top refiner, has signed long-term liquefied natural gas (LNG) import deals with United Arab Emirates’ s Abu Dhabi Gas Liquefaction Co Ltd (ADNOC LNG) and France’s TotalEnergies. The two deals were signed during Prime Minister Narendra Modi’s Visit to France and UAE last week. Supplies under the two deals would commence from 2026, the Indian company said in two separate statements. ADNOC LNG would supply up to 1.2 million metric tonnes per year (tpy) of LNG to IOC for 14 years, the Indian company said, adding India’s trade treaty with UAE enable it to import LNG without paying a 2.5% import tax. This is the first time that an Indian company has signed a long term LNG import deal with ADNOC. TotalEnergies would supply 0.8 million tpy LNG to IOC under the 10 year deal, it said. TotalEnergies would supply LNG to IOC from its global portfolio. India companies are spending billions of dollars to boost their gas infrastructure and are scouting for long term LNG imports deals as the nation wants to raise the share of gas in its energy mix to 15% by 2030 from 6.2% currently. IOC’s signings are also the latest in a slew of term deals signed by Asian LNG importers in recent months. In June, Bangladesh’s state-owned Petrobangla signed a 10-year contract to receive LNG supplies from OQ Trading, formerly known as Oman Trading International, and a 15-year suppy deal with QatarEnergy, starting 2026. Chinese importers Zhejiang Energy and ENN have also signed 20-year deals in recent weeks to receive North American supplies, after QatarEnergy inked 27-year agreements with China National Petroleum Corporation (CNPC) and Sinopec. Meanwhile, Thailand’s state-controlled PTT is in advanced talks with Qatar for a 15-year LNG deal for supplies of 1 or 2 million tonnes per annum, sources told Reuters.
Iraq Takes First Step Towards Becoming The World’s Biggest Oil Producer
Iraq’s parliamentary oil and gas committee plans to increase the country’s oil production to more than five million barrels per day, according to the release of committee minutes last week. As analysed in full in my new book on the new global oil market order, not only could this be done with relative ease by Iraq but it could also easily be the precursor to further oil production increases to 13 million barrels per day (bpd) if handled correctly. This would make Iraq the biggest oil producer in the world. In broad terms, Iraq remains the greatest relatively underdeveloped oil frontier in the world. Officially, according to the EIA, it holds a very conservatively-estimated 145 billion barrels of proved crude oil reserves (nearly 18 percent of the Middle East’s total, and the fifth biggest on the planet). Unofficially, it is extremely likely that it holds much more oil than this. In October 2010, Iraq’s Oil Ministry increased its own figure for the country’s proven reserves to 143 billion barrels. However, at the same time as producing the official reserves figures, the Oil Ministry stated that Iraq’s undiscovered resources amounted to around 215 billion barrels. This was also a figure that had been arrived at in a 1997 detailed study by respected oil and gas firm, Petrolog. Even this figure, though, did not include the parts of northern Iraq in the semi-autonomous region of Kurdistan. This meant, as highlighted by the IEA, that most of them had been drilled during a period before the 1970s began when technical limits and low oil prices gave a narrower definition of what constituted a commercially successful well than would be the case now. Overall, the IEA underlined that the level of ultimately recoverable resources across all of Iraq (including the Kurdistan region) at around 246 billion barrels (crude and natural gas liquids). Given the true scale of Iraq’s oil reserves – and the fact that the average lifting cost per barrel of oil in the country is US$1-2 pb (the lowest in the world, along with Iran and Saudi Arabia) – what sort of oil output could reasonably be expected? Back in 2013, the Integrated National Energy Strategy (INES) was produced, and this analysed in detail three realistic forward oil production profiles for Iraq and what each would involve. As also analysed in my new book, the INES’ best-case scenario was for crude oil production capacity to increase to 13 million bpd (at that point, by 2017), peaking at around that level until 2023, and finally gradually declining to around 10 million bpd for a long-sustained period thereafter. The mid-range production scenario was for Iraq to reach 9 million bpd (at that point, by 2020), and the worst-case INES scenario was for production to reach 6 million bpd (at that point, by 2020). Consequently, the 5 million bpd figure announced last week can be regarded as the first easily achievable stepping stone toward those figures. Indeed, according to Iraq’s Oil Minister, Hayan Abdel-Ghani, last week, the country’s oil production capacity already stands above this level – at 5.4 million bpd – although it is still only producing around 4.3-4.5 million bpd overall. The question at this point is, with these enormous reserves in place, and specific plans on how to turn these into up to 13 million bpd in the Oil Ministry’s files, why is Iraq not already producing a lot more oil than it is? The reason is the ongoing endemic corruption that lies at the heart of Iraq’s oil and gas industry. This not only removes enormous amounts of money from Iraq’s coffers that could fund much-needed infrastructure investments but also deters Western companies with the required technology, logistical expertise, and personnel from becoming too involved in the country. Although commissions are standard practice in the Middle East – and indeed across many business around the world – the practice has become something else entirely in Iraq. This has been highlighted repeatedly by OilPrice.com and independently over many years by Transparency International (TI) in various of its ‘Corruption Perceptions Index’ publications, in which Iraq normally features in the worst 10 out of 180 countries for its scale and scope of corruption. “Massive embezzlement, procurement scams, money laundering, oil smuggling and widespread bureaucratic bribery that have led the country to the bottom of international corruption rankings, fuelled political violence and hampered effective state building and service delivery,” TI states. “Political interference in anti-corruption bodies and politicisation of corruption issues, weak civil society, insecurity, lack of resources and incomplete legal provisions severely limit the government’s capacity to efficiently curb soaring corruption,” it concludes. The sums of money that Iraq has lost could have funded all the major projects needed to boost oil production up to at least 7 or 8 million bpd to begin with, notably the crucial Common Seawater Supply Project (CSSP), as also analysed in my new book. According to a statement made in 2015 by then-Oil Minister – and later Prime Minister of Iraq – Adil Abdul Mahdi, Iraq “lost US$14,448,146,000” from the beginning of 2011 up to the end of 2014 as “cash compensation” payments to international oil companies and to other entities. In basic terms, the way in which such a staggering sum was lost relates to the way in which gross remuneration fees, income tax and the share of the State partner was deducted and accounted for in the compensation paid out over reduced oil production levels. The sheer scale and scope of this corruption created the unwillingness of major Western firms to become too heavily involved in the country. In June 2021, U.K. oil super-major, BP, said it was working on a plan to spin off its operations in Iraq’s supergiant Rumaila oil field into a standalone company. The statement was highly reminiscent of the withdrawal of the U.K.-Dutch oil super-major, Shell, from Iraq’s supergiant Majnoon oil field in 2017 and of its withdrawal from Iraq’s supergiant West Qurna 1 oil field in 2018. Each of
Government reimposes windfall tax on domestic crude export
After a gap of two months, the government imposed the windfall tax on domestic crude oil production from nil to Rs 1,600 per tonne. However, there are no Special Additional Excise Duty (SAED) taxes on export of diesel, petrol or aviation turbine fuel (ATF). These changes are effective from July 15). In May 2023, the government cut the windfall tax on petroleum crude to zero from Rs 4,100 per tonne. Tax rates are reviewed fortnightly based on average oil prices in the previous two weeks. Global crude oil prices have risen again on the back of supply cuts by Saudi Arabia and Russia. The crude basket averaging below $75/bbl in May and June this year touched $80.92/bbl on July 13. India first imposed windfall profit taxes on 1 July 2022, joining a growing number of nations that tax supernormal profits of energy companies. At that time, export duties of Rs 6 per litre ($12 per barrel) each were levied on petrol and ATF and Rs 13 a litre ($26 a barrel) on diesel.
Gujarat’s green hydrogen projects to gain from NDB’s Climate Mitigation Fund
The ambitious big-ticket investments by key corporates in Gujarat in the green hydrogen sector are all set to gain big through the lending from New Development Bank (NDB). Since green infrastructure, green energy and climate mitigation projects are the NDB’s targets of investments in India, green hydrogen projects are expected to be co-financed by the bank, according to Leslie Maasdorp, vice president and chief financial officer, NDB. He is in Gujarat to attend the G20 Finance and Central Bank Deputies (FCBD) Meetings, being held at Mahatma Mandir in Gandhinagar from July 14-18. “Green hydrogen is a proven technology and can be scaled up. Therefore, the NDB is closely looking at co-financing these projects in India. Our aim at the NDB is to demonstrate and scale commercially viable projects in the areas of sustainability,” Maasdorp said, adding that NDB plans to continue investing in India at the rate of $1-$1.5 billion every year in India. TOI recently reported that the Gujarat cabinet approved the draft land allocation policy for green hydrogen projects. Land parcels of 1,99,000 hectare have been earmarked for five key players – private sector entities – eyeing their foray into the green hydrogen manufacturing. These include Reliance New Energy, Adani New Industries, Torrent Power, ArcelorMittal Nippon Steel India and Welspun Group.
India’s commissioning of floating LNG storage terminals to face further delays
India could witness further delays in commissioning and expansion of its floating liquefied natural gas (LNG) storage terminals with a total planned capacity of 30 million tonnes per annum (MTPA). The world’s fifth-largest LNG importer plans to add 30 MTPA of regasification capacity in a bid to import and store larger volumes of LNG to meet rising domestic demand. “India’s 5 MTPA Jafrabad FSRU and 6 MTPA H-Gas LNG Gateway have postponed their start-up from previous years and may see further delays due to tight supply globally for FSRU vessels and tepid local LNG demand due to recently high and volatile prices,” the International Gas Union (IGU) said in the world LNG report 2023. In the Jafrabad (Gujarat) FSRU, Swan Energy holds 32.12 per cent stake, followed by Indian Farmers Fertiliser Cooperative (30.87 per cent), Mitsui Group (11 per cent); Gujarat Maritime Board (15 per cent) and Gujarat State Petronet (11 per cent). The Jaigarh (Maharashtra) FSRU is controlled by H-Energy Gateway. businessline reached out to Swan Energy and H-Energy Gateway, but no responses were received. “Worth noting is that the floating terminals in India may face delays again this year due to the tight supply of FSRU vessels and increasing competition from European markets”, the report said. To increase regasification capacity, five new floating storage and regasification units (FSRUs) and two expansion projects are under construction in India. Of the five new terminals, three are floating-based, reflecting the South Asian market’s preference for floating terminals, it added. In October 2022, the International Energy Agency (IEA) had pointed out that rising demand in Europe has drawn away not only flexible LNG volumes from Asia but also the limited number of FSRU vessels available for hire in the foreseeable future. “Even projects with firm FSRUs can see their vessel commitments withdrawn. Hoegh LNG, for example, has recently terminated its 10-year FSRU charter with the much-delayed Jaigarh LNG project in India, and is now expected to redeploy the vessel to a new European FSRU terminal later this year,” it had said. Record high prices of LNG impacted imports, particularly among the price-conscious consumers in Asia. “While prices moderated closer to historically average levels at the start of 2023, they remain elevated with an ongoing risk of a return to 2022 conditions,” the report has projected. The report said that the Platts Japan-Korea Marker (JKM) benchmark, which reflects cargoes delivered into Northeast Asia, averaged $33.98 per million British thermal units (mBtu) in 2022, reaching an annual daily low of $18.945 per mBtu on January 20, 2022 and hitting an annual high, also an all-time high for the benchmark, at $84.762 on March 7, 2022. Asian demand reduced significantly in most locations, with the two fastest-growing major LNG markets in recent years, China, and India, both taking a major step back in procurement, reducing imports by 19.3 per cent Y-o-Y and 17.7 per cent Y-o-Y respectively. China’s LNG imports stood at 63.7 million tonnes (MT) in 2022, while India imported 19.4 MT. France replaced India and emerged as the fourth-largest LNG importer in 2022
China Is Quietly Building A Green Energy Empire In Latin America
China is rapidly expanding its green energy production and growth potential and, in doing so, is quickly gaining influence in key emerging markets around the world. While China is busily making inroads in renewable energy markets in Southeast Asia, Africa, and even the West, nowhere has its sphere of influence grown more rapidly or completely than in Latin America. China has been vastly outpacing the rest of the world in terms of clean energy spending, with more numerous and more developed clean energy supply chains than anywhere else on the planet. China alone was responsible for nearly half of all renewable energy spending worldwide in 2022, totalling a whopping $546 billion USD according to figures from a BloombergNEF analysis released early this year. This figure crushed the next-biggest spenders, the US and the EU: Beijing’s spending nearly quadrupled Washington’s $141 billion in clean energy spending, and was 2.5 times more than the EU’s $180 billion. China’s intensive spending on the sector has paid off; the country’s clean energy sectors are now economically independent enough to be weaned off of heavy government support, and are now outcompeting every other clean energy leader on the global stage. “China has managed to nurture these really integrated, efficient value chains for making things like solar panels, for making things like battery cells,” Antoine Vagneur-Jones, head of trade and supply chains research at BloombergNEF, was recently quoted by Scientific American. Due to the massive head start that China has in these sectors – not to mention its near-complete control over many rare Earth metals markets – it’s more than likely that Beijing will continue to dominate for at least the next decade, if not longer. This dynamic is especially pronounced in Latin America, where around 90% of all installed wind and solar technologies are produced by Chinese companies. As of 2023, Beijing has active free trade agreements with Chile, Costa Rica, Ecuador, and Peru (and is currently in negotiations with Uruguay), and so far 21 Latin American countries have signed on to China’s massive international infrastructure investing scheme, the Belt and Road Initiative (BRI). China’s State Grid now controls the majority of Chile’s regulated energy distribution. Similar problems are unfolding in Peru. Earlier this year, a Peruvian industry group warned that a major deal in development for a Chinese company to buy out two local power suppliers “would hand the Asian country a near monopoly over the sector in Peru, particularly in and around populous capital Lima.” The deal, which is still awaiting regulatory approval, would just be the latest of a long series of Chinese acquisitions in Peru. “If approved, it would lead to a concentration of 100% of Lima’s electricity distribution market in the hands of the People’s Republic of China,” the Peruvian National Society of Industries, a chamber of private companies, was quoted by Reuters. Beijing is also rapidly ramping up its investments in Latin American minerals. The continent is rich in key materials in renewable energy and electric vehicle manufacturing such as lithium, nickel, and cobalt. China is already the “dominant producer of rare earths and graphite globally,” The South China Morning Post recently reported based on recent BloombergNEF data. “It also owns around a third of global rare earths, a sixth of graphite and an eighth of lithium reserves.” And expanding its acquisitions of Latin American minerals is a key part of China’s strategy. Chinese companies already own major stakes in one of the largest lithium producers in Chile, has purchased a ‘major evaporative lithium project’ in Argentina, and has signed dozens of trade-strengthening agreements with Brazil. And China is not the only global power eyeing Latin American lithium. The United States, too, has a vested interest in forging trade agreements with the continent’s producers of rare Earth minerals. In fact, it’s a key part of the nation’s strategy to catch up with China and become competitive in renewable energy markets. However, countries in Latin America are increasingly talking about shying away from such agreements with the US and China in the interest of shoring up their own manufacturing industries and taking advantage of value-addition opportunities domestically.
Indian Importers Of Russian Oil Brace For Banking Problems
Indian refiners buying Russian crude are preparing for problems with their bankers as the flagship Russian oil grade topped the G7-imposed price caps. In a report citing sources from three Indian refiners, Bloomberg wrote today that the companies were bracing up for more requirements from banks before they grant them the loans to buy the cargoes. Russia’s flagship crude grade, which has been trading consistently below the price cap set by the G7 and the European Union, climbed above $60 per barrel on Wednesday and remained there. It is now, for the first time, that observers can judge if the price cap is actually working. Before, with Urals trading below it anyway, it could hardly be argued that the cap was doing anything to deliberately squeeze Russia’s oil export income. Earlier this week, energy analyst Vandana Hari from Vanda Insights noted that this price for Urals will be problematic for Indian buyers. “Indian banks have been extra cautious in the last few months for fear of sanctions, requiring the refiners to show that the free-on-board price of their cargo was below $60 in order to put the payment through,” Hari told Bloomberg. According to the more recent Bloomberg report, buyers expect their bankers to start asking for more evidence to verify the price, at which the crude is being bought. Also, importers of Russian crude will stop using Western insurance and tanker services – the basis on which the price cap was designed. As long as the price of the crude was below $60 per barrel, buyers could use Western shipping transport and insurance. If the price moved above $60 access to insurers and tanker owners in the West shut off. According to one of the sources that Bloomberg spoke to, a switch from dollars to other currencies for payments for Russian cargo was also an option under consideration.
Lower prices help RIL-BP, Nayara treble share in June diesel sales
Reliance-BP and Nayara Energy have nearly tripled their share of the country’s diesel sales to 9.4% in June from a year earlier, using price discounts to regain domestic customers they had lost last year while focusing on the high-margin export market. RIL-BP’s share in total diesel sales rose to 4% in June from 1.2% in the same month a year earlier. Rosneft-backed Nayara Energy’s share has expanded to 5.4% from 2%. Shell’s share remained stagnant at 0.1%. As a result, the share of state-run players has dropped to 90.5% from 96.7% despite BPCL and HPCLgaining marginally. Indian Oil Corp has been the only loser in the game, with its share declining to 41.4% from 49.1%. Indian Oil’s market share gain was equally dramatic last year, rising from 42.4% in June 2021 as it stepped in to fill the gap left by the private players.
India not looking to cut excise duty on fuel right now: Revenue Secretary Sanjay Malhotra
India is currently not looking at lowering the excise duty on petroleum and diesel with rates already quite low following the two cuts administered in November 2021 and May 2022, Revenue Secretary Sanjay Malhotra told Moneycontrol in an interview. “The government continuously monitors inflation and takes measures on excise as well as customs side to control it on need basis. This is ongoing exercise not only for petrol and diesel but also for many other essential produces,” Malhotra added. In November, 2021, the central government reduced the excise duty on per litre of petroleum by 5 rupees and on diesel by 10 rupees, while another round of cuts came in May, 2022, wherein the duty was lowered by 8 rupees on a litre of petrol and 6 rupees on diesel. The central government’s collections from excise duties have been pegged at 3390 billion rupees for the current fiscal, targeting a growth of nearly 6% over the revised estimates of the previous financial year. Infact, for FY23, the government has revised downwards the Budget estimate for mop up from excise duties by 150 billion rupees.
U.S. Shale Challenges OPEC With Record Production In 2023
Last year, oil prices hit multi-decade highs shortly after Russia invaded Ukraine, prompting the Biden administration to urge U.S. producers and OPEC to ramp up production at a faster clip so as to rein in spiraling oil prices. However, Saudi Arabia and its allies responded by doing the exact opposite, cutting production when oil prices started plummeting. Predictably, the United States and Europe were irked by the cartel’s defiance, with President Joe Biden’s administration accusing Saudi Arabia of colluding with Russia and supporting its war in Ukraine. Well, President Biden can at least thank his lucky stars that the U.S. Shale Patch paid heed to his clarion call: the Energy Information Administration (EIA) has forecast total U.S. output will hit 12.61M bbl/day in the current year, eclipsing the previous record of 12.32M bbl/day set in 2019’s and easily beating last year’s 11.89M bbl/day. U.S. crude oil output is up 9% Y/Y blunting OPEC’s efforts to keep supplies low in a bid to goose prices. There is little doubt the U.S. Shale Patch is largely responsible for keeping oil markets well supplied and oil prices low: Rystad Energy has estimated that whereas OPEC and its allies have announced cuts amounting to ~6% of 2022’s production, non-OPEC supply has made up for two-thirds of those cuts, with the U.S. accounting for half of that. Energy experts have generally been bearish about U.S. crude supply with many arguing it has already peaked, “The projection suggests the pace of US shale growth, one of the few sources of major new supply in recent year, is slowing despite oil prices hovering at around $90 a barrel, about double most domestic producers’ breakeven costs. If the trend continues, it would deprive the global market of additional barrels to help make up for OPEC+ production cuts and disruption to Russian supplies amid its invasion of Ukraine,” Bloomberg said, Bloomberg cited comments by ConocoPhillips (NYSE: COP) CEO Ryan Lance that rising costs as well as limited supplies of labor and equipment were some of the problems that were hamstringing efforts by U.S. shale producers to quickly ramp up production. However, Bloomberg also noted that the biggest factor behind the slowdown is a change of the playbook by the majority of U.S. shale companies from focussing on growth and expansion to more capital discipline and returning more cash to shareholders. Improved Efficiency Luckily for the Shale Patch, improving drilling and cost efficiency not only means they are able to squeeze more for less but they are also able to eke out a profit at much lower oil prices. According to J.P. Morgan, U.S. drilling and fracking costs have declined 36% since 2014, significantly lowering the breakeven points of many producers. For instance JPM points out that increased efficiency means EOG Resources (NYSE:EOG), for example, can earn as much from oil priced at $42/bbl today as it would have from $86/bbl oil in 2014; in contrast, Saudi Arabia reportedly requires ~$81/bbl oil to balance its books. The U.S. shale revolution dramatically reshaped the world energy markets. The shale boom was one of the most impressive growth stories, from take off in 2008 to the Permian stealing the mantle from Saudi Arabia’s Ghawar as the world’s highest producing oilfield in a little over a decade. Overall, Reuters has estimated that, “U.S. petroleum production is at least 10-11 million bpd higher than it would have been without horizontal drilling and hydraulic fracturing.’’ Unfortunately, the Shale Patch has lately been struggling to ramp up production due to a litany of challenges including pressure from investors to boost returns, limited equipment and workers as well as a lack of capital. But shale giant ExxonMobil Corp. (NYSE:XOM) is now betting that shale producers can double crude output from their existing wells by employing novel fracking technologies. “There’s just a lot of oil being left in the ground. Fracking’s been around for a really long time, but the science of fracking is not well understood,” Exxon Chief Executive Officer Darren Woods said Thursday at the Bernstein Strategic Decisions conference. Woods has revealed that Exxon is currently working on two specific areas to improve fracking. First off, the company is trying to frack more precisely along the well so that more oil-soaked rock gets drained. It’s also looking for ways to keep the fracked cracks open longer so as to boost the flow of oil. Shale Refracs Luckily, the U.S. Shale Patch won’t have to wait for Exxon to perfect its new fracking technologies. There’s already a proven technology for oil producers to return to existing wells and give them a second, high-pressure blast to increase output for a fraction of the cost of finishing a new well: shale well refracturing. Refracturing is an operation designed to restimulate a well after an initial period of production, and can restore well productivity to near original or even higher rates of production as well as extend the productive life of a well. Re-fracking can be something of a booster shot for producers–a quick increase in output for a fraction of the cost of developing a new well. While refracturing has never really gone mainstream, the technique is seeing higher adoption as drilling technology improves, aging oilfields erode output, and companies try to do more with less. According to a report published in the Journal of Petroleum Technology, new research from the Eagle Ford Shale in south Texas shows that refractured wells using liners are even capable of outperforming new wells despite the latter benefiting from more modern completion designs. JPT also estimates that North Dakota’s Bakken Shale straddles some 400 openhole wells capable of generating an excess of $2 billion if refractured. Mind you, that estimate is derived from oil prices at $60/bbl vs. this year’s average oil price of almost $90/bbl. According to Garrett Fowler, chief operating officer for ResFrac, a refrac can be up to 40% cheaper than a new well and double or triple oil flows from aging wells. How Refracs Work Fowler says the